EP3580425A1

EP3580425A1 - Downhole operations

Info

Publication number: EP3580425A1
Application number: EP18700131.8A
Authority: EP
Inventors: Carsten BUSK
Original assignee: Total E&P Danmark AS
Current assignee: Total E&P Danmark AS
Priority date: 2017-02-08
Filing date: 2018-01-09
Publication date: 2019-12-18
Anticipated expiration: 2038-01-09
Also published as: GB2559555A; WO2018145842A1; EP3580425B1; GB2559555B; US20200248544A1; GB201702025D0

Abstract

A method of creating a well bore comprises providing a bore liner (26) in a section of a well bore (20) extending through a formation (22) and providing the liner with at least one frac sleeve (28). A frac bottom hole assembly (BHA) (50) is mounted on a string (52) of jointed pipe and the BHA is run into the well bore through a blowout preventer (16) (BOP). The BHA is located adjacent the sleeve (28). A seal on the BOP is activated to engage the jointed pipe. The BHA (50) is activated to engage the frac sleeve (28). The BHA is then translated to open a port in the frac sleeve. A surface pump then delivers fracturing fluid through the port (174) into the formation surrounding the liner. After stopping the flow of fluid the BHA is translated to close the port in the frac sleeve.

Description

DOWNHOLE OPERATIONS

FIELD

This disclosure relates to methods and apparatus for use in creation of boreholes for accessing subsurface formations. The disclosure has particular application in operations where formations are subject to hydraulic fracturing.

BACKGROUND OF THE DISCLOSURE

In the oil and gas exploration and production industry bores are drilled from surface to access subsurface hydrocarbon-bearing rock formations. In certain formations, production of hydrocarbons may be enhanced by fracturing the rock to create fissures through which fluids may pass. These fissures may be created by a number of techniques, one being hydraulic fracturing, often referred to a tracking. In this technique, high pressure fluid is injected into the formation to fracture the rock. The fluid may take any appropriate form, and may comprise acid and may carry material, known a proppant, which lodges in the fissure and maintains the fissures open when the fluid pressure is reduced.

A drilled bore may comprise a vertical or near vertical portion which leads into a substantially horizontal portion extending through the hydrocarbon-bearing formation. The far or distal end of the horizontal portion may be referred to as the toe of the well, while the end of the horizontal portion adjacent the vertical portion may be referred to as the heel of the well. If the formation is to be subject to hydraulic fracturing, the process is normally carried out in stages, starting at the toe and working along the well to the heel. Given that high fluid pressures are employed during the fracturing operations, and the well bore is open to the formation during the fracturing operations, operators exercise great care in ensuring that the well remains fluid-tight and the well pressure is closely monitored and controlled. The fracturing operation may involve a suitable bottom hole assembly (BHA) mounted on a tubular support member which extends from surface. At or near surface, the support member may extend through a pressure containment apparatus such as a blowout preventer (BOP). The apparatus may provide a number of different sealing mechanisms to engage the outside of the support member and safely contain the well pressure. The high pressures utilised in fracturing operations may also result in the creation of forces which tend to push the support member out of the bore. Of course it is necessary to translate the support member through the various seals to locate the BHA at the appropriate location in the bore and this often requires manipulation of the surface sealing arrangement and may require the provision of apparatus to accommodate the pressure forces acting on the support. Accommodating these different requirements inevitably incurs significant time and expense.

SUMMARY OF THE DISCLOSURE

An aspect of the disclosure relates to a method of creating a well bore.

The method may comprise:

providing a bore liner in a section of a well bore extending through a reservoir formation and providing the liner with at least one valved port;

mounting a fluid delivery tool on a string of jointed pipe and running the fluid delivery tool into the well bore through pressure containment apparatus;

locating the fluid delivery tool adjacent the valved port;

activating a seal on the pressure containment apparatus to engage the jointed pipe;

activating the fluid delivery tool to engage the valved port;

translating the fluid delivery tool to open the port;

operating a pump to deliver fracturing fluid through the port and into the formation surrounding the liner;

at least reducing the flow of fluid; and

closing the port.

The pressure containment apparatus may comprise a blowout preventer

An aspect of the disclosure relates to a method of creating a well bore, the method comprising:

providing a bore liner in a section of a well bore extending through a reservoir formation and providing the liner with at least one valved port, wherein the bore liner is cemented within the well bore;

mounting a fluid delivery tool on a string of jointed pipe and running the fluid delivery tool into the well bore through a blowout preventer (BOP);

locating the fluid delivery tool adjacent the valved port; activating a seal on the BOP to engage the jointed pipe;

activating the fluid delivery tool to engage the valved port;

stripping the string of jointed pipe through the BOP while the seal on the BOP engages the jointed pipe to translate the fluid delivery tool to open the port;

at least reducing the flow of the fracturing fluid; and

stripping the string of jointed pipe through the BOP while the seal on the BOP engages the jointed pipe to translate the fluid delivery tool to close the port.

The method steps may be conducted in the sequence as listed above or may be conducted in a different sequence.

While the port is open the seal on the BOP engages the jointed pipe and the jointed pipe may be translated through the apparatus. When the port is closed the formation will be isolated from the well bore. Thus, the operator is not required to manage the well pressure, which facilitates many operations; seals provided on the BOP may be retracted or otherwise open and the jointed pipe may be translated through the BOP relatively quickly.

A plurality of spaced apart valved ports may be provided on the liner and the method may be repeated for each valved port, translating the fluid delivery tool between each port location. All of the ports on the liner may be opened and closed on a single run. In other embodiments only selected ports may be opened. The ports may be opened and closed in any appropriate sequence as desired by the operator, for example starting with the port closest to the toe of the well and working towards the port at the heel of the well.

The valved port may be opened or closed by application of pressure. The valved port may be opened or closed by mechanical force. The valved port may be normally closed, and in the absence of external influence may assume a closed configuration. The valved port may comprise a valve member such as an inner sleeve or barrel which is translatable to open and close the port. The valve member may be translatable towards the distal end of the liner to open the port. Of course the valved port may comprise other arrangements to open and close the port. The fluid delivery tool may comprise slips or other gripping arrangements. The fluid delivery tool may comprise a packer or other sealing arrangement. One or both of the slips and the packer may be weight-activated. The slips and the packer may be activated to engage a sleeve or barrel which is translatable to open or close the port.

The fluid delivery tool may comprise a fluid port and fluid pumped down through the string may exit the string through the outlet. The fluid delivery tool port may be located adjacent the open valved port in the liner.

The fracturing fluid may be of any appropriate form or composition. The fracturing fluid may carry proppant.

Displacement fluid may be delivered through the jointed pipe following the fracturing fluid. The fracturing fluid may be under displaced by the displacement fluid.

Cleaning fluid may be circulated through the well following closing the port. The cleaning fluid may be reverse circulated. The well bore may be filled with kill weight fluid, which fluid may be brine. Alternatively, the well bore may be filled with lighter fluid, and may be underbalanced.

A cement layer surrounding the liner may be fractured by fluid delivered through the port.

The bore liner may be installed in a horizontal well bore section.

The method may further comprise producing fluid from the formation. The fluid may be produced through the valved port. The valve port may be configured to permit fluid to be produced through the port, or fluid may be produced through an alternative port in the liner.

An aspect of the disclosure relates to a well created in accordance with the method of the disclosure. Another aspect of the present disclosure relates to an apparatus for creating a well bore.

The apparatus may comprise:

a bore liner for location in a section of a well bore extending through a formation and comprising at least one valved port which may be opened and closed;

a fluid delivery tool mounted on a string of jointed pipe and configured to be run into the well bore through a pressure control apparatus including a sealing arrangement, the fluid delivery tool being adapted to cooperate with the valved port whereby axial translation of the string of jointed pipe through the closed sealing arrangement of the pressure control apparatus at least one of opens and closes the port.

The apparatus may be provided in combination with one or more of the features described above with reference to the method of the disclosure.

The fluid delivery tool may form part of a bottom hole assembly (BHA). As used herein, the term bottom hole assembly (BHA) may refer to the lower portion of the string of jointed pipe.

The pressure control apparatus may be a blow out preventer (BOP).

Other aspects of the disclosure relate to a three position valved port and a port configured to facilitate formation of a proppant arc over the port. The various aspects of the disclosure may be used in combination, or individually.

The three position valved port may comprise a body defining the port and a valve member movable relative to the body, in a first position the valve member closing the port, in a second position the valve member opening the port to facilitate flow of fracturing fluid through the port, and in a third position the valve member opening the port and locating a proppant flow control member across the port. The proppant flow control member may take any appropriate configuration.

The port configured to facilitate formation of a proppant arc over the port is intended to encourage or facilitate the proppant material which aggregates at production ports, inlets or slots to form arcs spanning each port. The arcs may act as barriers for particles, thereby limiting or reducing sand production from the formation, or limiting or reducing the flow of proppant material back out of the formation.

The formation of the arcs may be promoted by modifying the geometry of the ports. In one example, outer edges of the ports may be provided with a bevelled geometry.

A port configured to facilitate formation of a proppant arc may form part of a filter or screen member. Outer and inner ports may be provided in the proppant control member. The inner ports may be smaller than the outer ports. One or both of the inner and outer ports may be configured to promote formation of proppant arcs.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other aspects of the present disclosure will now be described, by way of example, with reference to the accompanying drawings, in which:

Figure 1 is a schematic representation of a hydrocarbon-producing well; and Figures 2 through 17 illustrate steps in the method of creating the well of Figure

1 , wherein Figures 7a to 7d are schematic illustrations of a sleeve configuration.

DETAILED DESCRIPTION OF THE DRAWINGS

Figure 1 is a schematic representation of an offshore oil or gas well 10, with a rig 12 moored above the well 10. A riser 14 depends from the rig 12 to pressure containment apparatus such as a blowout preventer (BOP) 16. In this example the BOP 16 is provided on the seabed, though the other examples the pressure containment apparatus could be provided at any suitable location and take any suitable form. A vertical well section 18 extends into the earth below the BOP 16 and leads into a horizontal well section 20 which extends through a hydrocarbon-bearing formation 22. In the illustrated example various dimensions have been provided, relating to, for example, bore, liner, casing and conductor diameters. The skilled person will of course understand that these dimensions are provided merely by way of example, and that the disclosure is not limited to apparatus of these dimensions.

Figures 2 through 17 illustrate steps in a method for creating the well 10, and in particular in creating the horizontal well section 20. Reference is first made in particular to Figure 2, which illustrates the well 10 at a stage where an 8 ½ inch (21 .59cm) diameter horizontal bore 24 has been drilled through the formation 22 and provided with a 5 ½ inch (13.97cm) diameter liner 26 including a number of closable valved ports, such as frac sleeves 28 (the figures show twelve sleeves). The sleeves 28 are initially closed. The liner 26 has been hung off a 10 ¾ inch (27.31 cm) diameter liner 30, which has itself been hung off a 14 inch (35.56cm) diameter casing 32. Of course, in other embodiments the liner 26 could be hung off production casing rather than liner 30. The 14 inch (35.56cm) casing 32 sits within a 10 ¾ inch (27.31 cm) diameter tie-back casing 34 and a 20 inch (50.8cm) diameter conductor 36.

The 5 1/2 inch (13.97cm) liner 26 is cemented in the bore section 24; that is the annulus 38 between the liner 26 and the wall of the horizontal section 24 is filled with cement slurry 40. Once the cement 40 has set, as illustrated in Figure 3, the liner 26 is pressure tested. If considered necessary by the operator a cleanout string 42 is then run into the cemented liner 26 and a cleaning operation carried out to remove cement residue from within the liner 26, as illustrated in Figure 4. This may involve the use of brushes and reverse circulation of cleaning fluid 44. Next, the cleaning fluid 44 is displaced from the well by clean kill weight brine 46, as illustrated in Figure 5. The brine 46 has a density selected to produce a hydrostatic pressure in the liner 26 sufficient to prevent flow of hydrocarbons from the formation 22 into the well 10, although in other examples an operator may choose to use lighter fluid and may even have the well underbalanced. The cleanout string 42 is then pulled out of hole, as illustrated in Figure 6. The well 10 is now ready for fracturing and a fluid delivery tool, such as a fracturing bottom hole assembly (frac BHA) 50 is run into the well 10 on a work string 52, as illustrated in Figure 7. The frac BHA 50 may take any appropriate form, and an example of suitable frac BHA 50, and an example of a sleeve 28, is illustrated in Figures 7a to 7c of the drawings.

Figures 7a to 7c, illustrate a sleeve 28 comprising a barrel 176 located in a recess provided in the wall of the sleeve body 166. Figure 7a illustrates the sleeve 28 in a closed configuration, in which the barrel 176 and seals 100 isolate ports 174 in the sleeve body 166. The barrel 176 is axially movable relative to the body 166 to expose the ports 174. In the embodiment illustrated in Figure 7b, this has been achieved by locating the frac BHA 50 within the barrel 176 and activating slips 158 and a packer element 160 to engage the barrel 176 and applying an axial mechanical and pressure force to translate the barrel 176 downwards. In this open configuration fracturing fluid 194 may be pumped through the ports 174 and into the surrounding formation. Thereafter the barrel 176 may be moved, by pulling the frac BHA 50 upwards, to close the ports 174.

When it is subsequently desired to produce from the surrounding formation the barrel 176 may be moved to an intermediate position in which a ported section of the barrel 176 extends across the ports 174, as illustrated in Figure 7c. The ported section of the sleeve is provided with a proppant restrictor 102 defining apertures 104 which are dimensioned according to the size of the proppant particles present in the fracturing fluid 194. In particular, it is desired to prevent proppant particles from flowing back into the well. At present the proppant supplied during the latter stages of a tracking operation may be coated with resin, which resin tends to make the proppant "sticky" and be held in the formation, or bind with other proppant particles. However, the properties of the resin may create other issues, and present the operator with environmental and safe handling complications.

The openings 104 may be sized to have a diameter a selected multiple of the diameter of the average proppant particle. If the screen openings are smaller there is an increased likelihood that the openings will be blocked by the particles, and of the openings are larger there is an increased likelihood that the particles will pass through the openings with the produced fluid, this creating operational difficulties for the operator. Further, the openings 104 and the ports 174 are provided with bevelled edges 106, as illustrated in Figure 7d. There is a tendency for proppant particles to aggregate at the ports 174 and the openings 104. This provides a degree of filtering or screening, but also restricts flow through the ports 174 and openings 104. However, the beneficial effects of this aggregation may be maximised if the proppant particles can be encouraged to aggregate in an arcuate form, bridging rather than filling the ports 174 and openings 104. The provision of the bevelled edges 106 promotes the creation of arcs of proppant particles 108.

These beneficial effects may be achieved in other forms of openings, for example in slots.

The work string 52 has a diameter of 3 ½ inches (8.89cm) and is mounted on 5 ½ inch (13.97cm) diameter drill pipe 80. The work string 52 and drill pipe 80 are formed from multiple sections of pipe joined by threaded end connections. As such the strings 52, 80 are physically robust and are well suited to pushing the BHA 50 through a long horizontal bore section. The strings 52, 80 also provide a relatively large internal bore for delivery of large volumes of fracturing fluid at high pressure, as will be described.

A seal is provided at the proximal end of the vertical well section 18, at the BOP 16. The drill pipe 80 passes through the BOP 16 which, in the illustrated example, is located on the seabed. The BOP 16 will typically include a number of seal arrangements for engaging the outer surface of the drill pipe 80, for example an annular preventer 82 and rams 84. The annular preventer 82 will typically include a sealing element in the form of a large elastomeric doughnut that is mechanically squeezed inward to seal on the drill pipe 80. The rams 84 typically include two halves of a cover for the well that are split down the middle and define a cut-out that corresponds to the diameter of the drill pipe 80. Hydraulic rams may be operated to force the two halves of the cover together to seal the wellbore when the drill pipe 80 extends into the well 10.

Prior to or following the actuation of the packer element 160 on the frac BHA 50 to provide a lower seal one of the annular preventer 82 and rams 84 is closed around the drill pipe 80 to provide an upper seal. Surface pumps 86 are then operated to pressurise the fluid in the well 10 to a desired level and further weight is applied to the drill pipe 80. The combination of pressure and weight generate an axial force on the BHA 50 sufficient to open the ports 174, as described above with reference to Figure 7b. During this process the drill pipe 80 moves down through the actuated BOP seal, for example through the annular preventer 82, which maintains a sealing contact with the drill pipe surface; this is sometimes referred to as "stripping in".

The downward movement of the BHA 50 relative to the sleeve body 166 will continue until the distal end of the barrel 176 lands on a shoulder 90 on the body 166 below the recess 72. As the sleeve 28a is opened a pressure drop may be observed at surface. The pressure of the fluid in the well is then increased such that fluid is forced through the open sleeve 28a to break down the cement layer 40 surrounding the sleeve 28a and create fissures 92 extending from the liner 26 to the formation 22.

A predetermined volume of fracturing fluid 94 is then pumped down the drill pipe 80 and work string 52, through the ports 174 and the fissures 92 in the cement 40 and into the formation 22, as illustrated in Figure 8. The fracturing fluid 94 is followed by a volume of kill weight brine 96, the volume of brine 96 pumped into the well being selected to under-displace the fracturing fluid 94 by a predetermined volume, for example 3 bbl (477 litres), as illustrated in Figure 9. In other words, the brine 96 is pumped into the well until only 3 bbl (477 litres) of fracturing fluid 94 is calculated to remain within the work string 52. Of course, the skilled person will recognise that with other operators, and in other jurisdictions practice may vary. For example, some operators may prefer to over-displace the fracturing fluid.

With the pumps 86 now turned off, the sleeve 28a is then closed by pulling up on the drill string 80 and work string 52, through the still-closed BOP annular preventer 82. The corresponding movement of the BHA 50 will pull the barrel 176 back through the sleeve body 166 to close the ports 174.

Thus, the well 10 is only open to the formation 22 for a relatively short period while the ports 174 are open. Movement of the drill string 80 during this period is achieved by stripping in and out through the annular preventer 82. Accordingly, there is no requirement for the operator to manage well pressure, which greatly simplifies operations and allows most operations to be carried out far more quickly than would be the case if it was necessary to continually manage well pressure. The well 10 is then reverse circulated clean, as illustrated in Figure 10, with clean kill weight brine 46; the brine 46 is pumped down from surface through the annulus 97 around the drill pipe 80 and work string 52 and then passes into the work string 52 and travels to surface through the work string 52 and drill pipe 80, carrying any remaining fracturing fluid 94 to surface. The circulation of brine 46 may continue until the returns at surface are clean.

If desired, the annular preventer 82 may be opened once the ports 174 have been closed.

The drill pipe 80 and work string 52 are then pulled back to locate the frac BHA 50 in the second sleeve 28b, as illustrated in Figure 1 1 . The process as described above is then repeated to: strip in the string 80 in through the annular preventer 82 in the BOP 16 and open the sleeve 28b; pump fracturing fluid 94 through the open sleeve 28b into the formation 22 surrounding the sleeve 28b (Figure 12); under-displace the fracturing fluid 94 with kill weigh brine 46; strip out the strings 80, 52 to close the sleeve 28b (Figure 13); and then reverse circulate with clean kill weight brine 46 to clean the well 10 (Figure 14). This operation is repeated for each sleeve 28 until the entire length of the horizontal section has been fractured and then isolated by closing the last sleeve 28. Following the reverse circulation and cleaning of the fracturing fluid 94 used in the last fracturing operation (Figure 15), the work string 50 is run in to the end of the well 10 and further cleaning carried out be reverse circulation of clean kill weight brine 46 (Figure 16). Following the cleaning operation, the drill pipe 80 and work string 52 may be safely pulled out of hole to position the frac BHA 50 at the top of the liner 5 ½ inch (13.97cm) liner 26 (Figure 17).

The hydraulic fracturing operation as described above will typically be accomplished in a single run, without having to retrieve the BHA 50 to surface. There is also a significant time saving due to the limited time that the sleeves 28 are open and providing fluid communication with the formation 22; during most of this time the surface pumps 86 are operating and pumping high pressure into the formation 22, and the sleeves 28 are closed immediately after the pumps 86 are switched off. As a result there is little or no need to manage well pressure. If desired the drill pipe 80 and work string 52 may then be then be pulled out of hole (POOH).

The well has now been tracked and is ready to receive production tubing. When the operator chooses to commence production, some or all of the sleeves 28 may be opened. If considered necessary or desirable one or more of the sleeves 28 may be subsequently closed if, for example, a relatively large water fraction is being produced through the sleeve 28.

Those of skill in the art will appreciate that the examples described above are not intended to be limiting and that, for example, particular dimensions and parameters are provided only by way of example.

Claims

1. A method of creating a well bore, the method comprising:

(a) providing a bore liner in a section of a well bore extending through a formation and providing the liner with at least one valved port, wherein the bore liner is cemented within the well bore;

(b) mounting a fluid delivery tool on a string of jointed pipe and running the fluid delivery tool into the well bore through a blowout preventer (BOP);

(c) locating the fluid delivery tool adjacent the valved port;

(d) activating a seal on the BOP to engage the jointed pipe and activating the fluid delivery tool to engage the valved port;

(e) stripping the string of jointed pipe through the BOP while the seal on the BOP engages the jointed pipe to translate the fluid delivery tool to open the port;

(f) operating a pump to deliver fracturing fluid through the port and into the formation surrounding the liner;

(g) at least reducing the flow of the fracturing fluid; and

(h) stripping the string of jointed pipe through the BOP while the seal on the BOP engages the jointed pipe to translate the fluid delivery tool to close the port.

2. The method of claim 1 , wherein the steps are conducted in the sequence as listed in claim 1.

3. The method of claim 1 or 2, wherein while the port is open the seal on the BOP engages the jointed pipe as the jointed pipe is translated through the BOP.

4. The method of any preceding claim, comprising providing a plurality of valved ports on the liner.

5. The method of claim 4, comprising repeating steps (c) to (h) for each valved port.

6. The method of claim 4 or 5, comprising translating the fluid delivery tool between each valved port location.

7. The method of claim 4, 5 or 6, comprising opening and closing multiple valved ports in a single run.

8. The method of any preceding claim, comprising translating a valve member to open and close the valved port.

9. The method of claim 8, wherein in a first position the valve member closes the port, in a second position the valve member opens the port to facilitate flow of fracturing fluid through the port, and in a third position the valve member opens the port and locates a filter member across the port.

10. The method of any preceding claim, comprising activating at least one of a gripping arrangement and a sealing arrangement of the fluid delivery tool.

11 . The method of claim 10, comprising applying weight to the fluid delivery tool to activate at least one of the gripping arrangement and the sealing arrangement.

12. The method of claim 10 or 1 1 , comprising activating at least one of the gripping arrangement and the sealing arrangement to engage a barrel which is translatable to open and close the valved port.

13. The method of any preceding claim, comprising pumping fluid through the jointed pipe to exit the pipe through an outlet in the fluid delivery tool.

14. The method of claim 13, comprising locating the fluid delivery tool fluid outlet adjacent the open port.

15. The method of any preceding claim, comprising delivering displacement fluid through the jointed pipe following the fracturing fluid.

16. The method of any preceding claim, comprising reverse circulating cleaning fluid through the well following closing the port.

17. The method of any preceding claim, comprising at least partially filling the well bore with kill weight fluid.

18. The method of claim 18, comprising fracturing a cement layer surrounding the liner.

19. The method of any preceding claim, comprising installing the bore liner in a horizontal well bore section.

20. The method of any preceding claim, comprising producing fluid from the formation.

21. The method of claim 20, wherein the fluid is produced through the valved port.

22. The method of any preceding claim, comprising forming a proppant arc over the port.

23. A well created in accordance with the method of any preceding claim.

24. Apparatus for creating a well bore comprising:

25. The apparatus of claim 24, wherein the valved port comprises a sleeve body defining the port and a valve member movable relative to the body, in a first position the valve member closing the port, in a second position the valve member opening the port to facilitate flow of fracturing fluid out through the port, and in a third position the valve member opening the port to facilitate flow of production fluid in through the port.

26. A valved port comprising a sleeve body defining the port and a valve member movable relative to the body, in a first position the valve member closing the port, in a second position the valve member opening the port to facilitate flow of fracturing fluid through the port, and in a third position the valve member opening the port and locating a proppant restrictor across the port.

27. The apparatus of claim 24 or 25, or the valved port of claim 26, wherein the port is configured to facilitate formation of a proppant arc over the port.

28. The apparatus or valve port of claim 27, wherein an outer edge of the port is bevelled.

29. The apparatus or valved port of any of claims 24 to 28, wherein the proppant restrictor comprises flow ports having a smaller dimension than the port in the sleeve body, and wherein the flow ports are configured to facilitate formation of a proppant arc over the ports.

30. The apparatus or valved port of claim 29, wherein outer edges of the proppant restrictor flow ports are bevelled.

31 . A valved port configured to facilitate formation of a proppant arc over the port wherein an outer edge of the port is bevelled.