Patent Application
20240191576
Well stimulation is performed on wells in the oil and gas industry to increase the flow of fluid from the formation located around the wellbore. Well stimulation includes mitigating wellbore damage or improving the natural permeability of the formation. Well stimulation is achieved by creating high conductivity paths using fracturing methods or acidizing methods. While these techniques are commonly used in the industry, they lack control in placement of the high conductivity paths.
In a fracturing operation, the shape, direction, and size of fracture is dominated by formation properties such as maximum horizontal stress and the existence of shales. In an carbonate acidizing operation, the acid flow is dominated by the variation of the permeability in the treated zone and the nature of the formation rock. When acid treatments are pumped, the acid tends to migrate towards the areas of higher permeability rather than towards the tighter areas.
Other factors that effects the stimulation in carbonate reservoirs is the co-existence of limestone and dolomite in the treatment zone. This co-existence results in a difference in the impact of the treatment because of the difference in stress of these two type of rocks and the reaction kinetics that favor stimulating the limestone rather than the dolomite.
This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
This disclosure presents, in accordance with one or more embodiments methods and systems for accessing a formation. A system includes a wellbore, a primary tunnel. a jetting sub, a jetting needle, and a secondary tunnel. The wellbore is drilled into a formation. The primary tunnel is formed from the wellbore. The jetting sub is disposed within the primary tunnel. The jetting needle is connected to the jetting sub. The jetting needle is configured to jut out from the jetting sub to penetrate the formation when exposed to a pressure differential. The secondary tunnel is formed from the primary tunnel by a high-pressure jet of fluid exiting the jetting needle into the formation.
A system includes a wellbore, a primary tunnel, a drilling sub, a drilling needle, a turbine, and a secondary tunnel. The wellbore is drilled into a formation. The primary tunnel is formed from the wellbore. The drilling sub is disposed within the primary tunnel. The drilling needle has a drill bit and is connected to the drilling sub. The drill bit juts out from the drilling sub when a pressure differential is seen on the drilling needle. The turbine is located within the drilling needle. The turbine rotates the drill bit using fluid pressure. The secondary tunnel is drilled from the primary tunnel using the rotation of the drill bit.
A method includes drilling a wellbore into a formation, forming a primary tunnel from the wellbore, disposing a sub into the primary tunnel, extending a needle from the sub into the formation, and forming a secondary tunnel, from the primary tunnel, using the needle.
Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.
Specific embodiments of the disclosed technology will now be described in detail with reference to the accompanying figures. Like elements in the various figures are denoted by like reference numerals for consistency. The sizes and relative positions of elements in the drawings are not necessarily drawn to scale. For example, the shapes of various elements and angles are not necessarily drawn to scale, and some of these elements may be arbitrarily enlarged and positioned to improve drawing legibility. Further, the particular shapes of the elements as drawn are not necessarily intended to convey any information regarding the actual shape of the particular elements and have been solely selected for ease of recognition in the drawing.
In the following detailed description of embodiments of the disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure. However, it will be apparent to one of ordinary skill in the art that the disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.
Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as an adjective for an element (i.e., any noun in the application). The use of ordinal numbers is not to imply or create any particular ordering of the elements nor to limit any element to being only a single element unless expressly disclosed, such as using the terms “before”, “after”, “single”, and other such terminology. Rather, the use of ordinal numbers is to distinguish between the elements. By way of an example, a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements.
The drill string (108) may include one or more drill pipes (109) connected to form conduit and a bottom hole assembly (BHA) (110) disposed at the distal end of the conduit. The BHA (110) may include a drill bit (112) to cut into the subsurface rock. The BHA (110) may include measurement tools, such as a measurement-while-drilling (MWD) tool (114) and logging-while-drilling (LWD) tool 116. Measurement tools (114, 116) may include sensors and hardware to measure downhole drilling parameters, and these measurements may be transmitted to the surface using any suitable telemetry system known in the art. The BHA (110) and the drill string (108) may include other drilling tools known in the art but not specifically shown.
The drill string (108) may be suspended in wellbore (102) by a derrick (118). A crown block (120) may be mounted at the top of the derrick (118), and a traveling block (122) may hang down from the crown block (120) by means of a cable or drilling line (124). One end of the cable (124) may be connected to a drawworks (126), which is a reeling device that can be used to adjust the length of the cable (124) so that the traveling block (122) may move up or down the derrick (118).
The traveling block (122) may include a hook (128) on which a top drive (130) is supported. The top drive (130) is coupled to the top of the drill string (108) and is operable to rotate the drill string (108). Alternatively, the drill string (108) may be rotated by means of a rotary table (not shown) on the drilling floor (131). Drilling fluid (commonly called mud) may be stored in a mud pit (132), and at least one pump (134) may pump the mud from the mud pit (132) into the drill string (108). The mud may flow into the drill string (108) through appropriate flow paths in the top drive (130) (or a rotary swivel, if a rotary table is used instead of a top drive to rotate the drill string (108)).
In one implementation, a system (199) may be disposed at or communicate with the well site (100). System (199) may control at least a portion of a drilling operation at the well site (100) by providing controls to various components of the drilling operation. In one or more embodiments, system (199) may receive data from one or more sensors (160) arranged to measure controllable parameters of the drilling operation. As a non-limiting example, sensors (160) may be arranged to measure WOB (weight on bit), RPM (drill string rotational speed), GPM (flow rate of the mud pumps), and ROP (rate of penetration of the drilling operation).
Sensors (160) may be positioned to measure parameter(s) related to the rotation of the drill string (108), parameter(s) related to travel of the traveling block (122), which may be used to determine ROP of the drilling operation, and parameter(s) related to flow rate of the pump (134). For illustration purposes, sensors (160) are shown on drill string (108) and proximate mud pump (134). The illustrated locations of sensors (160) are not intended to be limiting, and sensors (160) could be disposed wherever drilling parameters need to be measured. Moreover, there may be many more sensors (160) than shown in
During a drilling operation at the well site (100), the drill string (108) is rotated relative to the wellbore (102), and weight is applied to the drill bit (112) to enable the drill bit (112) to break rock as the drill string (108) is rotated. In some cases, the drill bit (112) may be rotated independently with a drilling motor. In further embodiments, the drill bit (112) may be rotated using a combination of the drilling motor and the top drive (130) (or a rotary swivel if a rotary table is used instead of a top drive to rotate the drill string (108)).
While cutting rock with the drill bit (112), mud is pumped into the drill string (108). The mud flows down the drill string (108) and exits into the bottom of the wellbore (102) through nozzles in the drill bit (112). The mud in the wellbore (102) then flows back up to the surface in an annular space between the drill string (108) and the wellbore (102) with entrained cuttings. The mud with the cuttings is returned to the pit (132) to be circulated back again into the drill string (108). Typically, the cuttings are removed from the mud, and the mud is reconditioned as necessary, before pumping the mud again into the drill string (108). In one or more embodiments, the drilling operation may be controlled by the system (199).
The act of drilling a wellbore (102) introduces near-wellbore (102) damage caused by mud filtrate invasion, solids plugging pores, etc. Further, the formation (104) through which the wellbore (102) is drilled may be a tight formation (104), meaning that the permeability is low. In order to optimize production of fluids, the formation should be stimulated by forming high conductivity paths through the near-wellbore damage and through the tight formations. As such, embodiments disclosed herein present systems and methods for creating primary and secondary tunnels from a wellbore (102) to aid in the production of fluids.
In accordance with one or more embodiments, an anchoring device (204) is set in the wellbore (102). The wellbore (102) is shown as a cased hole meaning that a casing string (206) is cemented within the wellbore (102) that has been drilled using the drilling system outlined in
A whipstock (208) is connected to and located up hole from the anchoring device (204). The whipstock (208) may be run in conjunction with the anchoring device (204), or the whipstock (208) may be run and set up hole from the anchoring device (204) on a separate trip. The whipstock (208) is similar in shape to a wedge and has a sloped portion (210) that is used to direct a tool to a sidewall of the wellbore (102). The whipstock (208) is made out of any durable material known in the art, such as steel. The whipstock (208) is set in the wellbore (102) in such a way that the sloped portion (210) of the whipstock (208) is pointed towards the wellbore (102) in a location where the primary tunnel (200) will be formed, as shown in
A conveyance device (212) is shown disposed in the wellbore (102) and the primary tunnel (200). The conveyance device (212) has a bottom hole assembly made up of a bent pipe (214), a mud motor (216), a centralizer (218), and a mill bit (220). The conveyance device (212) may be a drill string (108) or coiled tubing.
The bent pipe (214) is pipe that has been deformed and is used to direct the mill bit (220) into the formation (104) at a particular angle such that the primary tunnel (200) may be drilled at that angle away from the wellbore (102). The centralizer (218) is a device fit around the conveyance device (212) used to maintain the conveyance device (212) and the bottom hole assembly in the center of the primary tunnel (200) and the wellbore (102)
A drilling fluid, such as drilling mud, may be pumped into the system from a surface location (not pictured) to circulate cuttings and cool equipment downhole. The mud motor (216) uses fluid pressure caused by the drilling fluid to rotate the mill bit (220). In accordance with one or more embodiments, the mill bit (220) is a type of drill bit (112) that is designed to be able to drill through metal, such as the casing string (206).
In accordance with one or more embodiments, the mill bit (220) has drilled the primary tunnel (200) by kicking off from the whipstock (208) into a sidewall of the wellbore (102), milling through the casing string (206), and breaking down rock in the formation (104) surrounding the wellbore (102). In further embodiments, more than one primary tunnel (200) may be drilled from the wellbore (102) without departing from the scope of the disclosure herein.
The wellbore (102) is shown as a cased hole meaning that a casing string (206) is cemented within the wellbore (102) that has been drilled using the drilling system outlined in
Prior to the deployment of the jetting hose (308), a drilling tool, not pictured, may be deployed into the bore (306) of the deflecting shoe (304) to drill a hole into the casing string (206) without departing from the disclosure herein. The jetting hose (308) is a hose that is flexible enough to maneuver through the bore (306) in the deflecting shoe (304) yet is strong enough to not fold in on itself when pressure is applied. The jetting hose (308) may be disposed in the deflecting shoe (304) using a drill string (108) or coiled tubing (310).
In accordance with one or more embodiments,
The jetting hose (308) is connected to the coiled tubing (310) through a connector (314). The connector (314) may house the jetting hose (308) and may be in electronic communication with the coiled tubing (310) such that a signal may be sent form the surface, through the coiled tubing (310), to the connector (314). The signal may instruct the connector (314) to extend the jetting hose (308) from the connector (314) and into the bore (306) of the deflecting shoe (304).
A fluid, such as water or acid, is pumped from the surface, through the coiled tubing (310) and jetting hose (308), and out of the nozzle (316) of the jetting hose (308). The nozzle (316) is designed to emit a high-pressure jet of fluid (302) into the formation (104). The high pressure and potential acidic nature of the jet of fluid (302) breaks down the rock in the formation (104) to form the primary tunnel (200).
The jet of fluid (302), along with any cuttings, is circulated to the surface through the production tubing (312). As the primary tunnel (200) is formed by the high-pressure jet of fluid (302), the jetting hose (308) may further extend from the coiled tubing (310) to extend the length of the primary tunnel (200). In further embodiments, more than one primary tunnel (200) may be drilled from the wellbore (102) without departing from the scope of the disclosure herein.
While
When the drilling sub body (500) is exposed to a pressure differential, a plurality of drilling needles (502) may jut out from the drilling sub body (500). In accordance with one or more embodiments, the drilling needles (502) jut from the drilling sub body (500) into the formation (104) that is surrounding the primary tunnel (200). The drilling needles (502) are hollow and are hydraulically connected to the drilling sub body (500). The drilling needles (502) have an internal turbine, not pictured, that uses the fluid pressure to rotate the drill bit (504).
The drill bit (504) may be a miniature version of the drill bit (112) used to drill the wellbore (102) or the drill bit (504) may be similar to drill bits used for construction purposes. Each drill bit (504) may have a fluid outlet that allows the fluid to exit the drill bit (504) to circulate cuttings from the secondary tunnels (400). In terms of production of fluids, the fluid outlet may also act as a fluid entrance for production fluids to enter the drilling sub (402a).
Each drill bit (504) may be connected to a drilling needle (502) by a threaded connection, a welded connection, or a machined connection. In further embodiments, each drilling needle (502) is expandable, and retractable, to a set length away from the drilling sub (402a). The drilling needles (502) may be able to migrate from the drilling sub (402a) using the fluid pressure and space created by drilling, i.e., dissolving the rock with reactive fluid, and removing rock from the secondary tunnel (400). Further, the drilling needles (502) may be designed to expand from a shorter size to a longer size using a collapsible design, or the full length of the drilling needle (502) may be located within the drilling sub body (500).
When a pressure differential is seen across the jetting sub body (600), a plurality of jetting needles (602) may jut out from the jetting sub body (600). In accordance with one or more embodiments, the jetting needles (602) jut from the jetting sub body (600) into the formation (104) that is surrounding the primary tunnel (200). The jetting needles (602) are hollow and are hydraulically connected to the jetting sub body (600). Each jetting needle (602) is equipped with a nozzle (604).
A fluid, such as water or acid, is pumped from the surface, through the jetting sub and out of the nozzle (604) of the jetting needle (602). The nozzle (604) is designed to emit a high-pressure jet of fluid (302) into the formation (104) from the primary tunnel (200). The high pressure and potential acidic nature of the jet of fluid (302) breaks down the rock in the formation (104) to form the secondary tunnel (400).
In further embodiments, each jetting needle (602) is expandable, and retractable, to a set length away from the jetting sub (402b). The jetting needles (602) may be able to migrate from the jetting sub (402b) using the fluid pressure and space created by breaking down, i.e., dissolving the rock with reactive fluid, and removing rock from the secondary tunnel (400). Further, the jetting needles (602) may be designed to expand from a shorter size to a longer size using a collapsible design, or the full length of the jetting needle (602) may be located within the jetting sub body (600).
In other embodiments, the jetting needle (602) or the drilling needle (502) may be bent using a mechanical joint (700), such as a knuckle joint.
The mechanical joint (700) transforms the compressional load on the needle (502, 602) on a rotation to change the direction of the secondary tunnel (400). The needle (502, 602) may be rotated by sending an electronic signal from the surface to the sub (402) using wired drill pipe in a drill string (108), wired production tubing (312), or coiled tubing (310).
In further embodiments, the fluid used with the drilling sub (402a) or with the jetting sub (402b) may be mixed with fluid tracers. Fluid tracers have identifiable features such as color or composition that may be used to mark and identify the secondary tunnels (400). In accordance with one or more embodiments, production fluids, such as hydrocarbons, are produced from the formation (104) and the fluid tracers left over in the secondary tunnels (400) are produced with the initial production of the production fluids. Thus, identification of the fluid tracers at the surface enable a person or machine to determine where the production fluid is coming from.
Initially, a wellbore (102) is drilled into a formation (104) (S800). The wellbore (102) may be drilled using any drilling techniques and any drilling system known in the art. An example drilling system that may be used is outlined in
A primary tunnel (200) is formed from the wellbore (102) (S802). The primary tunnel (200) may be formed using a radial drilling system (202), such as the radial drilling system (202) outlined in
A sub (402) is disposed into the primary tunnel (200) (S804). The sub (402) may be installed or temporarily located within the primary tunnel (200). The sub (402) may be installed as a semi-permanent fixture on production tubing (312) and may be used to produce through as described in
A needle (502, 602) is extended from the sub (402) into the formation (104) (S806), and a secondary tunnel (400) is formed from the primary tunnel (200) using the needle (502, 602) (S808). In further embodiments, each sub (402) has a plurality of needles (502, 602), and a plurality of secondary tunnels are formed from one or more primary tunnels (200) using the plurality of needles (502, 602). Further, a single primary tunnel (200) may include one or more subs (402).
In accordance with one or more embodiments, the sub (402) may be a drilling sub (402a) and the needle (502, 602) may be a drilling needle (502). Further, the drilling sub (402a) may have a plurality of drilling needles (502) as shown in
In other embodiments, the sub (402) may be a jetting sub (402b) and the needle (502, 602) may be a jetting needle (602). Further, the jetting sub (402b) may have a plurality of jetting needles (602) as shown in
The fluid is emitted from a nozzle of each jetting needle (602) as a high-pressure jet of fluid (302). The high-pressure jet of fluid dissolves and/or breaks apart the formation (104) to form the secondary tunnel (400). After the secondary tunnels (400) have been formed, the fluids may be circulated from the primary tunnels (200), secondary tunnels (400), and wellbore (102) with clean brine or a slow reacting chemical.
In further embodiments, each needle (502, 602) may have a mechanical joint (700) used to direct the path of the secondary tunnels (400). In other embodiments, a fluid tracer may be mixed with the fluid used to operate the jetting sub (402b) and/or the drilling sub (402a). The fluid tracer may be used to mark and identify the secondary tunnels (400).
Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.
