Patent Application
20160177657
The field relates to fracturing balls. The fracturing balls are used prior to conducting hydraulic fracturing operations to prevent fluid flow downstream of the ball.
The features and advantages of certain embodiments will be more readily appreciated when considered in conjunction with the accompanying figures. The figures are not to be construed as limiting any of the preferred embodiments.
As used herein, the words “comprise,” “have,” “include,” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps.
It should be understood that, as used herein, “first,” “second,” “third,” etc., are arbitrarily assigned and are merely intended to differentiate between two or more wellbore intervals, zones, etc., as the case may be, and does not indicate any particular orientation or sequence. Furthermore, it is to be understood that the mere use of the term “first” does not require that there be any “second,” and the mere use of the term “second” does not require that there be any “third,” etc.
As used herein, a “fluid” is a substance having a continuous phase that tends to flow and to conform to the outline of its container when the substance is tested at a temperature of 71° F. (22° C.) and a pressure of one atmosphere “atm” (0.1 megapascals “MPa”). A fluid can be a liquid or gas.
As used herein, the relative term “downstream” means at a location further away from a wellhead. As used herein, the relative term “upstream” means at a location closer to the wellhead.
Oil and gas hydrocarbons are naturally occurring in some subterranean formations. In the oil and gas industry, a subterranean formation containing oil, gas, or water is referred to as a reservoir. A reservoir may be located on land or off shore. Reservoirs are typically located in the range of a few hundred feet (shallow reservoirs) to a few tens of thousands of feet (ultra-deep reservoirs). In order to produce oil or gas, a wellbore is drilled into a reservoir or adjacent to a reservoir. The oil, gas, and/or water produced from the wellbore is called a reservoir fluid.
A well can include, without limitation, an oil, gas, or water production well, an injection well, or a geothermal well. As used herein, a “well” includes at least one wellbore. The wellbore is drilled into and penetrates a subterranean formation. The subterranean formation can be a part of a reservoir or adjacent to a reservoir. A wellbore can include vertical, inclined, and/or horizontal portions, and it can be straight, curved, and/or branched. As used herein, the term “wellbore” includes any cased, and any uncased, open-hole portion of the wellbore. A near-wellbore region is the subterranean material and rock of the subterranean formation surrounding the wellbore. As used herein, “into a well” means and includes into any portion of the well, including into the wellbore or into the near-wellbore region via the wellbore.
A portion of a wellbore may be an open hole or cased hole. In an open-hole wellbore portion, a tubing string may be placed into the wellbore. The tubing string allows fluids to be introduced into or flowed from a remote portion of the wellbore. In a cased-hole wellbore portion, a casing is placed into the wellbore, which can also contain a tubing string. A wellbore can contain one or more annuli. Examples of an annulus include, but are not limited to: the space between the wall of the wellbore and the outside of a tubing string in an open-hole wellbore; the space between the wall of the wellbore and the outside of a casing in a cased-hole wellbore; and the space between the inside of a first tubing string and the outside of a second tubing string, such as a casing.
It is not uncommon for a wellbore to extend several hundreds of feet or several thousands of feet into a subterranean formation. The subterranean formation can have different zones. A zone is an interval of rock differentiated from surrounding rocks on the basis of its fossil content or other features, such as faults or fissures. For example, one zone can have a higher permeability compared to another zone. It is often desirable to treat one or more locations within multiples zones of a formation. One or more zones of the formation can be isolated within the wellbore via the use of an isolation device. An isolation device can be used for zonal isolation and functions to block fluid flow within a tubular, such as a tubing string, or within an annulus. The isolation devices can be used to create multiple intervals of the wellbore. There can be one or more intervals of the wellbore that correspond to a zone of the subterranean formation. The blockage of fluid flow prevents the fluid from flowing across the isolation device in any direction and isolates the formation zone of interest. In this manner, treatment techniques can be performed within the zone of interest.
A common isolation device is a ball and a seat (commonly called a baffle). It is to be understood that reference to a “ball” is not meant to limit the geometric shape of the ball to spherical, but rather is meant to include any device that is capable of engaging with a baffle. A “ball” can be spherical in shape, but can also be a dart, a bar, or any other shape. The baffle is attached to the inside of a tubing string, for example a casing. Zonal isolation can be accomplished via the ball and baffle by dropping or flowing the ball from the wellhead onto the baffle that is located within the wellbore. The ball engages with the baffle, and the seal created by this engagement prevents fluid communication into other zones downstream of the ball and baffle within the tubing string. In order to treat more than one zone using a ball and baffle, the wellbore can contain more than one baffle. For example, a baffle can be located within each wellbore interval. Generally, the inner diameter (I.D.) of the tubing string where the baffles are located is different for each interval. For example, the I.D. of the tubing string sequentially decreases at each interval, moving from the wellhead to the bottom of the well. In this manner, a smaller ball is first dropped into a first interval that is the farthest downstream; that zone is treated; a slightly larger ball is then dropped into another interval that is located upstream of the first interval; that zone is then treated; and the process continues in this fashion—moving upstream along the wellbore—until all the desired zones have been treated.
A common treatment performed in a subterranean formation zone is hydraulic fracturing (commonly called fracing for short). In hydraulic fracturing, a fracturing fluid is pumped at a sufficiently high flow rate and high pressure through the wellbore and into the near wellbore region to create or enhance a fracture in the subterranean formation. Creating a fracture means making a new fracture in the formation. Enhancing a fracture means enlarging a pre-existing fracture or fissure in the formation. A frac pump is used to pump the fracturing fluid into the wellbore and formation at high rates and pressures, for example, at a flow rate in excess of 10 barrels per minute (315 U.S. gallons per minute) at a pressure in excess of 5,000 pounds force per square inch (“psi”). The creation or enhancement of a fracture creates a highly-permeably flow path for oil, gas, water, or combinations thereof to be produced from the subterranean formation into the wellbore.
In order to conduct fracing operations, the tubing string or casing can include one or more ports. The baffle can be attached to a sliding sleeve. When the sleeve is in the closed position, the ports are closed to fluid flow through the port and in the open position, the ports are open to fluid flow through the ports. When a frac ball is dropped or pumped into the wellbore, the baffle moves downward, thus shifting the sliding sleeve and opening the ports. The frac ball engages with the baffle to isolate the zone being fractured. Now that the ports are open and fluid is prevented from flowing downstream of the ball and baffle, the fracturing fluid can be pumped through the ports and into the subterranean formation to create the fractures.
Isolation devices can be classified as permanent or retrievable. While permanent isolation devices are generally designed to remain in the wellbore after use, retrievable devices are capable of being removed after use. It is often desirable to use a retrievable isolation device in order to restore fluid communication between one or more wellbore intervals. For example, after all fractures have been created in each desired zone, a reservoir fluid would then be produced from the formation. Therefore, it is desirable to remove the frac balls so the reservoir fluid can flow into the wellbore and to the wellhead. Traditionally, isolation devices are retrieved by inserting a retrieval tool into the wellbore, wherein the retrieval tool engages with the isolation device, attaches to the isolation device, and the isolation device is then removed from the wellbore. Another way to remove an isolation device from the wellbore is to mill at least a portion of the device or the entire device. Yet, another way to remove an isolation device is to contact the device with a solvent, such as an acid, thus dissolving all or a portion of the device.
However, some of the disadvantages to using traditional methods to remove a retrievable isolation device include: it can be difficult and time consuming to use a retrieval tool; milling can be time consuming and costly; and premature dissolution of the isolation device can occur. For example, premature dissolution can occur if acidic fluids are used in the well prior to the time at which it is desired to dissolve the isolation device.
A novel method of removing a frac ball includes providing a high-strength, low specific gravity ball that can be flowed from the wellbore after use. The frac ball can be made of a metal or metal alloy and can be a hollow ball. It is to be understood that as used herein, the term “metal” is meant to include pure metals and also metal alloys without the need to continually specify that the metal can also be a metal alloy. Moreover, the use of the phrase “metal or metal alloy” in one sentence or paragraph does not mean that the mere use of the word “metal” in another sentence or paragraph is meant to exclude a metal alloy. As used herein, the term “metal alloy” means a mixture of two or more elements, wherein at least one of the elements is a metal. The other element(s) can be a non-metal or a different metal. An example of a metal and non-metal alloy is steel, comprising the metal element iron and the non-metal element carbon. An example of a metal and metal alloy is bronze, comprising the metallic elements copper and tin.
According to an embodiment, a method of restricting fluid flow within a tubing string of a wellbore comprises: introducing a ball into the tubing string, wherein the ball: (A) comprises a metal or a metal alloy; (B) is a shell having an outer diameter and an inner diameter; and (C) has a specific gravity less than or equal to a necessary specific gravity such that the ball flows toward a wellhead of the wellbore after a desired amount of time; and causing or allowing the ball to engage a baffle, wherein after engagement a fluid is prevented from flowing across the ball.
Any discussion of the embodiments regarding the ball or any component related to the ball (e.g., the baffle) is intended to apply to all of the apparatus and method embodiments. Any discussion of a particular component of an embodiment (e.g., a ball, a baffle, etc.) is meant to include the singular form of the component and also the plural form of the component, without the need to continually refer to the component in both the singular and plural form throughout. For example, if a discussion involves “the ball,” it is to be understood that the discussion pertains to one ball (singular) and two or more balls (plural).
Turning to the Figures,
The tubing string 15/16 and/or the casing 12 can include one or more ports 17. The one or more ports 17 can be located in each section of the tubing string. Moreover, not every section of the tubing string needs to include the one or more ports 17. For example, the first section of tubing string 15 can include one or more ports 17, while the second section of tubing string 16 does not contain a port. In this manner, fluid flow into the annulus 19 for a particular section can be selected based on the specific oil or gas operation.
It should be noted the well system 10 that is illustrated in the drawings and is described herein is merely one example of a wide variety of well systems in which the principles of this disclosure can be utilized. It should be clearly understood that the principles of this disclosure are not limited to any of the details of the well system 10, or components thereof, depicted in the drawings or described herein. Furthermore, the well system 10 can include other components not depicted in the drawing. For example, the well system 10 can further include a sand control assembly or a gravel pack assembly. By way of another example, cement may be used instead of packers 18 to create wellbore intervals. Cement may also be used in addition to packers 18.
The ball 31/32 can be a fracturing ball. The ball 31/32 comprises a metal or metal alloy. Preferably, the ball 31/32 comprises steel, aluminum, magnesium, or combinations thereof. According to an embodiment, the metal is neither radioactive, unstable, nor theoretical. If more than one ball is used, the metal or metal alloy can be the same or different. A different metal or metal alloy may be useful when the outer diameter and/or shell thickness of the balls is different.
The ball 31/32 is a shell having an outer diameter (O.D.) and an inner diameter (I.D.). That is, the ball is a hollow ball having a wall(s) that makes up the shell. The ball 31/32 can have a shell thickness. The shell thickness of the ball 31/32 is the difference between the O.D. and I.D. of the ball. The ball 31/32 can have an O.D. selected such that the ball is capable of engaging with a baffle 41/42. The baffle 41/42 can be located on the inside of a tubing string. The baffle can include protrusions that make up an engagement diameter. The ball 31/32 can have an O.D. that is greater than the engagement diameter to allow the ball to land on the baffle. In this manner, at least a portion of the outside of the ball comes in contact with and interferes with a portion of the baffle. This engagement of the ball with the baffle can create a seal within the tubing string at the baffle/ball location and prevent fluid flow across the ball (e.g., from a first wellbore interval to a second wellbore interval within the tubing string). Accordingly, the engagement of the ball 31/32 with the baffle 41/42 prevents fluid flow between a first wellbore interval and a second wellbore interval. The first wellbore interval can be located upstream or downstream of the second wellbore interval. In this manner, depending on the oil or gas operation, fluid is restricted or prevented from flowing downstream or upstream into the second wellbore interval. The fluid is prevented from flowing through the tubing string past the ball, either upstream or downstream of the ball based on the orientation of the baffle and the direction of fluid flow. The sizes of the baffles and balls are selected based on the I.D. of the tubing string. According to an embodiment, the O.D. of the ball 31/32 is selected based on the I.D. of the tubing string in which the ball is to be used. According to another embodiment, the ball 31/32 has an O.D. in the range of about 1 inch to about 4.5 inches (about 2.5 cm to about 11.4 cm).
The ball 31/32 has a specific gravity less than or equal to a necessary specific gravity such that the ball flows to a wellhead (not shown) of the wellbore 11 after a desired amount of time. The desired amount of time can be the time necessary to complete a hydraulic fracturing operation. According to an embodiment, the ball 31/32 has a specific gravity in the range of about 0.5 to about 2, preferably about 1 to about 1.5. If more than one ball is used, the specific gravity for each ball can be the same or different. The exact specific gravity of the ball will depend on the metal or metal alloy chosen, the shell thickness of the ball, and the O.D. of the ball. For example, as the O.D. of the ball increases, the shell thickness may have to decrease to obtain the desired specific gravity due to the overall amount of material used to make up the ball. Of course, the reverse may also be true that as the O.D. decreases, the shell thickness may be increased. By way of another example, a ball made of aluminum could have a greater shell thickness compared to a ball made of steel when the two balls have the same O.D. due to the difference in densities between the materials making up the balls. As can be seen, variation in the metal or metal alloy chosen, the shell thickness, and the O.D. of the ball can equally play an important part in the resulting specific gravity of the ball. According to an embodiment, the metal or metal alloy, the shell thickness, and the O.D. of the ball are selected such that the ball has the specific gravity.
According to an embodiment, the ball 31/32 is capable of withstanding a desired pressure differential after engagement with the baffle 41/42. The desired pressure differential can be less than or equal to the amount of pressure the ball can withstand. As used herein, the term “withstanding” means that the ball does not crack, break, collapse, or lose structural integrity. The pressure differential can be the downhole pressure of the subterranean formation 20 across the ball. As used herein, the term “downhole” means the location of the wellbore where the ball 31/32 is located. Formation pressures can range from about 1,000 to about 30,000 pounds force per square inch (psi) (about 6.9 to about 206.8 megapascals “MPa”). The pressure differential can also be created during oil or gas operations. For example, a fluid, when introduced into the wellbore 11 upstream or downstream of the ball 31/32, can create a higher pressure above or below, respectively, of the ball. Pressure differentials can range from 100 to over 10,000 psi (about 0.7 to over 68.9 MPa).
As discussed above regarding the specific gravity of the ball, the metal or metal alloy chosen, the O.D. of the ball, and the shell thickness of the ball all play an important part in the pressure differential the ball is capable of withstanding. By way of example, as the O.D. of the ball increases, the ball may not be capable of withstanding a specific pressure differential with the same shell thickness. Therefore, as the O.D. increases, the shell thickness may also have to be increased to provide the desired pressure rating. By way of another example, the strength of metals and metal alloys can be different. As a result, if a stronger metal is used, then the shell thickness may be decreased while still allowing the ball to withstand the desired pressure differential. According to an embodiment, the ball 31/32 has the desired specific gravity (i.e., the ball has a specific gravity less than or equal to the necessary specific gravity such that the ball flows toward the wellhead of the wellbore after the desired amount of time) and is capable of withstanding the desired pressure differential. According to another embodiment, the metal or metal alloy, the shell thickness, and the O.D. of the ball are all selected such that the ball has the desired specific gravity and is capable of withstanding the desired pressure differential.
The methods include the step of introducing the ball into the tubing string. The methods can also include introducing a first ball into a first section of tubing string and introducing a second ball into a second section of tubing string. As can be seen in
According to another embodiment, a method of creating one or more fractures in a zone of a subterranean formation comprises: (A) introducing the ball into a tubing string of a wellbore, wherein the wellbore penetrates the subterranean formation; (B) causing or allowing the ball to engage a baffle, wherein after engagement a fluid is prevented from flowing across the ball; (C) creating the one or more fractures in the zone of the subterranean formation, wherein the fluid is prevented from flowing across the ball prior to and during the creation of the one or more fractures; and (D) producing a reservoir fluid from the zone of the subterranean formation, wherein the production of the reservoir fluid occurs after the creation of the one or more fractures, and wherein the ball flows towards the wellhead prior to or during the production of the reservoir fluid.
The ball (whether it be a first ball 31 or a second ball 32) can engage a sliding sleeve 33 during introduction. The sliding sleeve 33 can be located adjacent to the port 17. The sliding sleeve 33 can be in a closed position as depicted in
The methods can include creating one or more fractures 50 in the zone of the subterranean formation 20. The methods can further include creating one or more fractures 50 in more than one or multiple zones of the subterranean formation 20. The methods can also include introducing a fracturing fluid into the well. In order to create the fractures, the ball 31/32 should maintain engagement with the baffle 41/42 such that fluid is prevented from flowing across the ball 31/32 and the ball should also be capable of withstanding the pressure differential being applied across the ball. In this manner, the fracturing fluid can flow into the tubing string, out the open ports, and create the fractures in the formation instead of flowing past the ball.
The methods can also include producing a reservoir fluid from the zone of the subterranean formation 20. The reservoir fluid can be oil, gas, water, or combinations thereof in any proportion. The methods can further include producing the reservoir fluid from more than one or multiple zones of the subterranean formation 20. The production of the reservoir fluid occurs after the creation of the one or more fractures 50.
The ball can flow towards the wellhead of the wellbore prior to or during the production of the reservoir fluid. The methods can further include the step of flowing the ball or all the balls towards the wellhead. In some instances, it may be desirable to flow the ball(s) towards the wellhead prior to producing the reservoir fluid. This may be accomplished by causing a fluid to flow through the annulus 19 and up the tubing string to flow the ball(s) towards the wellhead. It may also be desirable to allow the balls to flow towards the wellhead during production of the reservoir fluid. This may be accomplished via the reservoir fluid flowing into the bottom of the tubing string and/or into the tubing string via the opened ports. The reservoir fluid will then flow towards the wellhead carrying the ball(s) with it. The specific gravity of the ball can be selected based on the density of the produced reservoir fluid. By way of example, crude oil has a higher density compared to shale gas. Therefore, the specific gravity of a ball used for producing crude oil can be higher than the specific gravity of a ball used for producing shale gas. According to an embodiment, the specific gravity of the balls is selected such that all balls located within the tubing string are flowed towards the wellhead. After flowing towards the wellhead, the balls can be removed from the wellbore.
Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is, therefore, evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present invention. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods also can “consist essentially of” or “consist of” the various components and steps. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an”, as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent(s) or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/US2013/056416 | 8/23/2013 | WO | 00 |
