Patent Application
20160362957
In the course of producing oil and gas wells, typically after the well is drilled, the well may be completed. One way to complete a well is to divide the well into several zones and then treat each zone individually.
Treating each section of the well individually may be accomplished in several ways. One way is to assemble a tubular assembly on the surface where the tubular assembly has a series of spaced apart sliding sleeves. Sliding sleeves are typically spaced so that at least one sliding sleeve will be adjacent to each zone. In some instances annular packers may also be spaced apart along the tubular assembly in order to divide the wellbore into the desired number of zones. In other instances when annular packers are not used to divide the wellbore into the desired number of zones the tubular assembly may be cemented in place.
The tubular assembly is then run into the wellbore typically with the sliding sleeves in the closed position. Once the tubular assembly is in place in the well and has been cemented in place or the packers have been actuated the wellbore may be treated.
The wellbore treatment typically consists of high pressure pumping of a viscosified fluid containing a proppant down through the tubular assembly out of the specified sliding sleeve and into the formation. The high-pressure fluid tends to form cracks and fissures in the formation letting the viscosified fluid carry the proppant into the cracks and fissures. When the treatment ends, the proppant remains in the cracks and fissures holding the cracks and fissures open and allowing wellbore fluid to flow from the formation zone, through the open sliding sleeve, into the tubular assembly, and then to the surface.
To open a sliding sleeve, an obturator, such as a ball, a dart, etc., is dropped into the wellbore from the surface and pumped through the tubular assembly. The obturator is pumped through the tubular assembly to the sliding sleeve where it lands on the seat of the sliding sleeve and forms a seal with the seat on the sliding sleeve to block all further fluid flow past the ball and the seat. As additional fluid is pumped into the well the differential pressure formed across the seat and ball provides sufficient force to move the sliding sleeve from its closed position to its open position. Fluid may then be pumped out of the tubular assembly and into the formation so that the formation may be treated.
In order to selectively open a particular sliding sleeve the obturator may be sized so that it will pass through the sliding sleeves until finally reaching the sliding sleeve where the seat size matches the size of the obturator. In practice the sliding sleeve with the smallest diameter seat is located closest to the bottom or toe of the well. Each sliding sleeve above the lowest sliding sleeve has a seat with a diameter that is slightly larger than the seat below it. By using seats that step up in size as they get closer to the surface, a small diameter obturator may be dropped into the tubular assembly and will pass through each of the larger diameter seats on each sliding sleeve above the lowest sliding sleeve. The obturator finally reaches the sliding sleeve with a seat diameter that matches the diameter of the obturator. The obturator and seat blocked the fluid flow past the sliding sleeve actuating the particular sliding sleeve.
Progressively larger obturators are launched into the tubular assembly to selectively open each sliding sleeve. Each seat and obturator must be sized so that the seat provides sufficient support for the obturator at the anticipated pressure. Currently there seems to be an upper limit on the number of sliding sleeves that may be actuated by progressively larger obturators and seats thereby limiting the productivity of a single well. An additional limitation of the current technology is that by utilizing progressively smaller seats towards the bottom of the well the productivity of the well is further limited as each seat chokes fluid flow from the bottom of the well towards the top of the well. Therefore in practice there is usually the additional step of drilling out the seats adding further costs to completing the well.
In order to overcome the limitations of utilizing sequentially sized seats and obturators the current invention provides an actuation dart for actuating the tool in a wellbore.
A wellbore dart or pill is provided such that each time the dart passes through a downhole tool having a seat and externally extending finger is forced radially inward into the dart. In this instance the seat may merely consist of a protrusion to interact with the externally extending finger on the dart. As the finger moves inward to its depressed position, the finger moves a ball or other placeholder from a first position to a second position. When the ball is moved to the second position it may be released into the interior of the wellbore or it may be released into a chamber in the tool. In any event the ball is moved to a second position such that it may not return to the first position when the finger returns from its depressed position to its extended position.
It is envisioned that a number of placeholders or balls will be stacked within the dart waiting to move into the first position adjacent the externally extending finger. The number of balls are placeholders correlate to the number of seats that the dart move through. For instance fifty balls may be placed such that the balls may move into the first position one at a time. As the dart passes each seat the finger is depressed moving the ball in the first position to the second position where it is released. The finger then returns to its extended position allowing the next ball to move into the first position. When all of the, for instance fifty, balls have been released the follower that is moving the balls into the first position will finally move into the first position itself. However the follower is constructed such that when the follower is in the first position the externally extending finger is locked radially outward. When the dart reaches the next seat as the radially extending finger is no longer able to move from its extended position to its depressed position thereby allowing the dart to move past seat the dart locks into the particular seat. The dart may seal on the seat or it may seal on a portion of the tool adjacent to the seat. In either event once the dart is locked into a particular seat fluid pressure may be increased from the surface allowing the dart to actuate the particular tool within which the seat is located.
Each zone in a wellbore may then be accessed by using an indexing dart with its indexing mechanism set to correspond to the particular wellbore tool and seat combination. The number of zones that may be accessed with a single size seat at indexing dart combination is limited only by the number of placeholders that may be carried within the dart.
It is envisioned that most darts will have more than one ball indexing mechanism. It is also envisioned that each dart will be configured to closely fit within the seat in order to allow an increase in fluid pressure when the dart is locked on a particular seat. In many instances the dart may carry a secondary ceiling mechanism in order to increase the dart's ability to seal on a particular seat. Additionally as it is envisioned that the darts will need to be removed from the wellbore the leading edge, the trailing edge, or both of each dart will be equipped with at least one castellation or other anti-rotation device to allow for easy mill out of each dart. In certain instances it in this envisioned that the dart may be constructed of a dissolvable or erodable material.
The description that follows includes exemplary apparatus, methods, techniques, and instruction sequences that embody techniques of the inventive subject matter. However, it is understood that the described embodiments may be practiced without these specific details.
As the dart 200 reaches seat 74 the finger 234 and collet 232 cannot be depressed radially causing dart 200 to become lodged in place with respect to seat 74. As pressure from the surface is increased the ability of shear pin 62 to retain sliding sleeve 42 in position is surpassed there by shifting sliding sleeve 42 from its closed position as shown to an open position allowing fluid access from the interior of the tubing assembly 12 through port 63 into formation zone 22.
Bottom, lower, or downward denotes the end of the well or device away from the surface, including movement away from the surface. Top, upwards, raised, or higher denotes the end of the well or the device towards the surface, including movement towards the surface. While the embodiments are described with reference to various implementations and exploitations, it will be understood that these embodiments are illustrative and that the scope of the inventive subject matter is not limited to them. Many variations, modifications, additions and improvements are possible.
Plural instances may be provided for components, operations or structures described herein as a single instance. In general, structures and functionality presented as separate components in the exemplary configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the inventive subject matter.
