Patent Application
20060070740
This invention relates to a system and method for fracturing a hydrocarbon-producing formation with a fracturing system located in a wellbore adjacent the formation.
Hydraulic fracturing is often utilized to stimulate the production of hydrocarbons from subterranean formations penetrated by wellbores. Such hydraulic fracturing treatments typically include perforating the well casing adjacent the formation and introducing a fracturing fluid through tubing into a tool assembly in the casing, and to a ported sub, or the like, connected in the tool assembly. The fluid discharges from the ported sub at a relatively high pressure and passes through the perforations in the well casing and into the formation to fracture it and promote the production of the hydrocarbons such as oil and/or gas. Where only one portion of a formation is to be fractured as a separate stage, it is isolated from the other perforated portions of the formation using conventional packers or the like, and a fracturing fluid is pumped into the wellbore through the perforations in the well casing and into the isolated portion of the formation to be stimulated at a rate and pressure such that fractures are formed and extended in the formation. Propping agent may be suspended in the fracturing fluid which is deposited in the fractures. The propping agent functions to prevent the fractures from closing, thereby providing conductive channels in the formation through which produced fluids can readily flow to the wellbore. In certain formations, this process is repeated in order to thoroughly populate multiple formation zones or the entire formation with fractures.
In situations where casing is not present, it is sometimes desirable to use the above approach to create a preferential center of fracture point. In general, this center of fracture point coincides with the center of the tubing or casing. Such a method is described in U.S. Pat. No. 5,765,642, where a jetting tool is used to place such fractures, with or without the use of isolation methods.
However, these types of techniques are not without problems. For example, it is typically not possible with traditional fracturing technology to direct the fracture in a specific direction, as fractures are controlled primarily by the mechanics of the formation and the wellbore. In traditional fracturing methods, the center of the fracture is in the center of the tubing or casing. This may result in fracturing into water-producing formations or fracturing into another known undesirable fracture or well. Such methods may also result in fracturing in the direction of least principle stress creating near-wellbore-toruosity during the fracture treatment and possible formation sand flowback problems.
Also, with traditional methods of well fracture it is typically not possible to determine the exact location and orientation of the ported sub, and hence, the exact location of the fractures to be formed. Further, traditional hydraulic fracturing tools most often lack critical equipment necessary to complete other procedures in the wellbore, such as packing, orientation and the like. These traditional hydraulic fracturing tools must most often be removed from the wellbore and other tools inserted for such additional procedures, resulting in additional time and costs. Therefore, what is needed is a fracturing system and method that eliminates the above problems.
The present invention is directed to an apparatus and method for fracturing and/or perforating a formation.
More specifically, one embodiment of the present invention is directed to a method of fracturing a subterranean formation penetrated by a wellbore by positioning a fracturing tool within the wellbore, with the fracturing tool having a fracturing tool outer wall. A fracture is initiated with the center of fracture point located within the subterranean formation but not within the wellbore. A fracture is then created.
Another embodiment of the present invention is directed to a method of fracturing a subterranean formation penetrated by a wellbore by positioning a hydrajetting tool assembly within the wellbore. The hydrajetting tool assembly has a hydrajetting sub capable of being inserted into a wellbore. The hydrajetting tool assembly includes a hydrajetting sub defined by an outer wall and an inner fluid flow passageway, and a port formed through the outer wall and adapted to communicate with the inner fluid flow passageway, a nozzle mounted within the port, and a directional sub, wherein the directional sub is mechanically connected to the hydrajetting sub. A fracture is initiated, wherein the center of fracture point is located within the subterranean formation but not within the wellbore by introducing a fracturing fluid into the inner fluid flow passageway of the hydrajetting sub and jetting the fracturing fluid through the nozzle against the subterranean formation at a pressure sufficient to form cavities in the formation, wherein the cavities in the formation are in fluid communication with the wellbore. A fracture is created by maintaining the fracturing fluid in the cavities while jetting at a sufficient static pressure to fracture the subterranean formation.
Still another embodiment of the present invention is directed to a hydrajetting tool assembly mechanically connected to a work string, wherein the work string comprises an outer wall and an inner wall. The hydrajetting tool assembly is capable of being inserted into a wellbore and includes a hydrajetting sub defined by hydrajetting sub outer wall, an inner fluid flow passageway, and a port formed through the outer wall adopted to communicate with the inner fluid flow passageway. The hydrajetting tool assembly further includes a nozzle mounted within the port and a directional tool mechanically connected to the hydrajetting sub.
A more complete understanding of the present disclosure and advantages thereof may be acquired by referring to the following description taken in conjunction with the accompanying drawings:
a is an overview of a subterranean formation fractured using a fracturing tool of the present invention in a mostly vertical section of a wellbore.
b is an overview of a subterranean formation fractured using a fracturing tool of the present invention in a mostly horizontal section of a wellbore.
c is an overview of a subterranean formation fractured using a fracturing tool of the present invention in a mostly vertical section of a wellbore
As described above, it is typically not possible with traditional fracturing technology to direct the fracture in a specific direction. Further, traditional fracturing methods typically have a center of fracture point in the center of the tubing or casing.
A fracturing operation in a substantially vertical section of wellbore 1100 using a fracturing tool of the present invention is depicted in
a further depicts directional tool 2100. Directional tool 2100 is mechanically connected to fracturing tool 2000. Directional tool 2100 may be any one of a number of devices suitable for determining both the inclination and azimuth angle of fracturing tool 2000. Suitable examples of directional tool 2100 include, but are not limited to, gyroscopic surveyors, wireline steerers, memory pulsed neutron logging devices, and electromagnetic logging devices. Note that directional tool 2100 may include those types of tools described below as types of directional sub 40. Through the use of the combination of directional tool 2100, the operator may determine the inclination and azimuth angle of fracturing tool 2000. The operator may then rotate fracturing tool 2000 to the appropriate predetermined position, either through the use of surface equipment or downhole equipment. Thus, the operator may, through the use of the combination of fracturing tool 2000 and directional tool 2100 to create center of fracture point 1250 at any location about wellbore 1100 as desired.
By orienting nozzles at an angle from fracturing tool wall 2030, as shown in
Referring now to
Hydrajetting tool assembly 10 is comprised of at least hydrajetting sub 20 and directional sub 40. Referring to
Ports 21 are generally approximately circular openings, although other shapes may be used depending on the particular design parameters. Ports 21 are designed to allow the mounting of nozzles 22 within ports 21. Nozzles 22 are designed to allow fluid flow from inner fluid flow passageway 18 through hydrajetting sub outer wall 24. Nozzles 22 are further designed to cause fluid impingement on formation 1150, as shown in
In typical embodiments, nozzles 22 have a diameter sized so as to increase the pressure of the fluid being jetted through nozzles 22 to a suitable pressure to cause microfractures in formation 1150 or to perforate any wellbore casing that may be present. The increased pressure allowed by reducing the diameter of nozzles 22 increases the pressure drop of fluid traveling through nozzles 22. Nozzles 22 may be composed of any material that is capable of withstanding the stresses associated with fluid fracture of formation 1150 and the abrasive nature of the fracturing or other treatment fluid and any proppants or other fracturing agents used. Nonlimiting examples of an appropriate material of construction of nozzles 22 are tungsten carbide and certain ceramics.
Mechanically connected to hydrajetting sub 20 in one embodiment of the present invention is downhole power unit (DPU) 14. DPU 14 is a self-contained unit designed to provide electrical power to downhole equipment, such as the equipment described below. DPU 14 is most commonly a device containing a battery, a fuel cell or a fluid motor/generator combination. An acceptable device for use as DPU 14 is the Downhole Power Unit available from Halliburton Energy Services, Inc. In at least one embodiment of the present invention, DPU 14 is electrically connected to work string 12 so as to allow data transmission to DPU 14 through the conducting materials within the walls of work string 12. DPU 14 may be located above hydrajetting sub 20, as shown in
Hydrajetting sub 20 is typically mechanically connected, either directly, as shown in
In particular embodiments of the present invention, hydrajetting sub 20 may be mechanically connected to check valve 200. Check valve 200, as shown in
Hydrajetting tool assembly 10 may in certain embodiments include packing device 300. Packing device 300 is any one of a number of packers known to those of skill in the art for sealing the wellbore. This seal is designed to isolate the portion of the formation to be fractured from portions below or beyond hydrajetting tool assembly 10. It is not expected that the seal formed by packing device 300 be complete, but it should be sufficient to allow fracturing of the desired formation. Typically, packing device 300 will seat against the sides of the wellbore or well casing to form this seal. Packing device 300 is typically located below hydrajetting sub 20.
Hydrajetting tool assembly 10 further includes directional sub 40. Directional sub 40 may include any number of devices suitable for determining both the inclination and azimuth angle of hydrajetting tool assembly 10. Suitable examples of directional sub 40 include, but are not limited to, gyroscopic surveyors, wireline steerers, memory pulsed neutron logging devices, and electromagnetic logging devices, all of which are familiar to those of ordinary skill in the art. Directional sub 40 is designed to communicate with surface equipment through such communications means as mud pulse, sonic, and wireline. Directional sub 40 may be powered by DPU 14 or, in the alternative, may be powered by an integrated power system, typically a device containing batteries. Alternatively, for instance, in embodiments where DPU 14 is absent, directional sub 40 may be powered from the surface through conducting material located within the wall of work string 12. Directional sub 40 is mechanically connected to hydrajetting sub 20. In some embodiments of the present invention, directional sub 40 is located such that other equipment, for example packing device 300, is mechanically located between directional sub 40 and hydrajetting sub 20. Such positioning may be desirable to lessen vibrational effects of hydrajetting sub 20 on sensitive electronic or mechanical components of directional sub 40.
Additional equipment that may be included in hydrajetting tool assembly 10 includes a hole finder, i.e., a device commonly used in drilling to find holes in piping such as liners or casing, gamma radiation source, a device used to determine, and a collar locator, i.e., a device designed to detect drill pipe collars. Typically, this additional equipment will be located contiguous with directional sub 40, although any appropriate location on hydrajetting tool assembly 10 may be used for such equipment.
Referring now to
Hydrajetting tool assembly 10 is positioned in wellbore 1100 adjacent to the portion of formation 1150 to be fractured. Packing device 300 is then set so that if forms a seal as described above in wellbore 1100. In one embodiment of the present invention wherein check valve 200 is used, a fluid is pumped through work string 12 and through hydrajetting tool assembly 10, whereby the fluid flows through the check valve 200 and circulates through wellbore 1100. The circulation is preferably continued for a period of time sufficient to clean debris, pipe dope and other materials from inside work string 12 and from wellbore 1100. Thereafter, ball 210 is dropped through work string 12, through hydrajetting sub 20 and into check valve 200 while continuously pumping fluid through work string 12 and hydrajetting tool assembly 10. When ball 210 seats on annular seating surface 208 in check valve 200, fluid is forced through nozzle 22 of hydrajetting sub 20. The rate of pumping the fluid into the work string 12 and through the hydrajetting sub 20 is increased to a level whereby the pressure of the fluid which is jetted through the nozzles 22 reaches a desired jetting pressure.
In sections of open hole wellbore 1100 having wellbore casing 410, it may be necessary to perforate wellbore casing 410 before forming microfractures, such as through the use of hydrajetting sub 20. Hydrajetting sub 20 may be used to make a number of different types of perforations in wellbore casing 410, commonly described as “cuts.” For instance, in certain formations, wellbore casing 410 may be perforated in only a single direction, e.g., towards the surface. In such a case, where nozzles 22 are oriented in one direction, fluid may be forced through nozzles 22 in that single direction. Generally, in such situations, directional sub 40 is used to determine the orientation of hydrajetting sub 20. Hydrajetting sub 20 may then be oriented through rotation, either by rotating sleeve 16 or from surface equipment, so that nozzles 22 point in the desired direction. Fluid may then be forced through nozzles 22 to make the single direction cut.
Where it is desirable to make multiple perforations at different circumferential locations about wellbore casing 410, after the initial perforation, fluid flow through nozzles 22 may be stopped, hydrajetting sub 20 may be rotated, as described above, to a different circumferential location, and fluid flow through nozzles 22 restarted. This process may be repeated as necessary to completely perforate wellbore casing 410. In other situations, it may be desirable to make a longitudinal cut of wellbore casing 410, called a “vertical cut” when the longitudinal cut is made in mostly substantially vertical portion 404. When a longitudinal cut is desired, hydrajetting tool assembly 10 is raised or lowered while fluid is jetted through nozzles 22. In addition, it certain situations it may be desirable to make a spiral cut of wellbore casing 410. Normally, a spiral cut is made when it is necessary to cut the wellbore casing 410 around its entire circumference, for instance, when the well is to be abandoned. In such a situation, fluid is jetted through nozzles 22 while hydrajetting sub 20 is rotated, either by use of rotating sleeve 16 or through the use of surface equipment.
Further, fluid jetted through nozzles 22 may be used to cause the creation of the cavities 50 and microfractures 52 in formation 1150 as illustrated in
As will be described further hereinbelow, the jet differential pressure (Pjd) at which the fluid must be jetted from nozzles 22 to result in the formation of the cavities 50 and microfractures 52 in the formation 1150 is a pressure of approximately two times the pressure (Pi) required to initiate a fracture in the formation less the ambient pressure (Pa) in the wellbore adjacent to the formation i.e., Pjd≧2×(PI−Pa). The pressure required to initiate a fracture in a particular formation is dependent upon the particular type of rock and/or other materials forming the formation and other factors known to those skilled in the art. Generally, after a wellbore is drilled into a formation, the fracture initiation pressure can be determined based on information gained during drilling and other known information. Since wellbores are often filled with drilling fluid and since many drilling fluids are undesired, the fluid could be circulated out, and replaced with desirable fluids that are compatible with the formation. The ambient pressure in the wellbore adjacent to the formation being fractured is the hydrostatic pressure exerted on the formation by the fluid in the wellbore or a higher pressure caused by fluid injection.
As mentioned above, propping agent may be combined with the fluid being jetted so that it is carried into the cavities 50 into fractures 60 connected to the cavities. The propping agent functions to prop open fractures 60 when they attempt to close as a result of the termination of the fracturing process. In order to insure that propping agent remains in the factures when they close, the jetting pressure is preferably slowly reduced to allow fractures 60 to close on propping agent which is held in the fractures by the fluid jetting during the closure process. In addition to propping the fractures open, the presence of the propping agent, e.g., sand, serves as an abrasive agent and in the fluid being jetted facilitates the cutting and erosion of the formation by the fluid jets. As indicated, additional abrasive material can be included in the fluid, as can one or more acids which react with and dissolve formation materials to enlarge the cavities and fractures as they are formed.
As further mentioned above, some or all of the microfractures produced in a subterranean formation can be extended into the formation by pumping a fluid into the wellbore to raise the ambient pressure therein. That is, in carrying out the methods of the present invention to form and extend a fracture in the present invention, hydrajetting sub 20 is positioned in wellbore 1100 adjacent the portion of formation 1150 to be fractured and fluid is jetted through the nozzles 22 against the formation 1150 at a jetting pressure sufficient to form the cavities 50 and the microfractures 52. Simultaneously with the hydrajetting of the formation, a fluid may be pumped into wellbore 1100 at a rate to raise the ambient pressure in wellbore 1100 adjacent formation 1150 to a level such that the cavities 50 and microfractures 52 are enlarged and extended whereby enlarged and extended fractures 60 are formed. As shown in
Following the fracture of formation 1150, the annulus or wellbore may be “packed,” i.e., a packing material may be introduced into the fractured zone to reduce the amount of fine particulants such as sand from being produced during the production of hydrocarbons. The process of “packing” is well known in the art and typically involves packing the well adjacent the unconsolidated or loosely consolidated production interval, called gravel packing. In a typical gravel pack completion, a sand control screen is lowered into the wellbore on a workstring to a position proximate the desired production interval. As described above, this sand control screen may be included as a part of hydrajetting tool assembly 10, typically below packing device 300. A fluid slurry including a liquid carrier and a relatively coarse particulate material, which is typically sized and graded and which is referred to herein as gravel, is then pumped down the workstring and into the well annulus formed between the sand control screen and the perforated well casing or open hole production zone.
The liquid carrier either flows into the formation or returns to the surface by flowing through a wash pipe or both. In either case, the gravel is deposited around the sand control screen to form the gravel pack, which is highly permeable to the flow of hydrocarbon fluids but blocks the flow of the fine particulate materials carried in the hydrocarbon fluids. As such, gravel packs can successfully prevent the problems associated with the production of these particulate materials from the formation.
In another embodiment of the present invention, the proppant material, such as sand, is consolidated to better hold it within the microfractures. Consolidation may be accomplished by any number of conventional means, including, but not limited to, introducing a resin coated proppant (RCP) into the microfractures.
Another operation possible using at least one embodiment of the present invention is known to those of skill in the art as a cement squeeze. Following perforation or fracturing, evaluation of perforation or fracturing operation may be determined by the operator to be inadequate. In such a situation, the operator may wish to close the perforations or isolate formation 1150 from wellbore 1100. Following the perforation or fracturing operation, cement may be pumped down work string 12 and out nozzles 22 of hydrajetting sub 20. After setting, the cement acts to close the perforations of well casing 410 or isolate formation 1150 from wellbore 1100.
Therefore, the present invention is well-adapted to carry out the objects and attain the ends and advantages mentioned as well as those which are inherent therein. While the invention has been depicted, described, and is defined by reference to exemplary embodiments of the invention, such a reference does not imply a limitation on the invention, and no such limitation is to be inferred. The invention is capable of considerable modification, alteration, and equivalents in form and function, as will occur to those ordinarily skilled in the pertinent arts and having the benefit of this disclosure. The depicted and described embodiments of the invention are exemplary only, and are not exhaustive of the scope of the invention. Consequently, the invention is intended to be limited only by the spirit and scope of the appended claims, giving full cognizance to equivalents in all respects.
