US20190063198A1

US20190063198A1 - System, method, and apparatus for hydraulic fluid pressure sweep of a hydrocarbon formation within a single wellbore

Info

Publication number: US20190063198A1
Application number: US16/114,808
Authority: US
Inventors: Scott Anderson; Michael J. Harvey
Original assignee: Flow Resource Corp Ltd
Current assignee: Flow Resource Corp Ltd
Priority date: 2017-08-28
Filing date: 2018-08-28
Publication date: 2019-02-28

Abstract

A system for recovering production fluid includes a return string for receiving fluid from a lateral section of a wellbore. The return string can extend from a surface of a terrestrial formation through at least a portion of the wellbore. The system also includes an injection string for communicating fluid from the surface of the terrestrial formation to the lateral section of the wellbore. The injection string includes a first injection string section located at a distal end of the injection string and for communicating fluid through at least a portion of the lateral section of the wellbore. The injection string includes a second injection string section located at a proximal end of the injection string and for communicating fluid from the surface of the terrestrial formation to the first injection string section. The second injection string section includes a smaller cross-sectional area than the first injection string section.

Description

CROSS-REFERENCE TO RELATED APPLICATION AND PRIORITY CLAIM

This Application claims priority under 35 U.S.C. § 119(e) to U.S. Provisional Patent Application No. 62/551,102 filed on Aug. 28, 2017. The above-identified provisional patent application is hereby incorporated by reference in its entirety.

TECHNICAL FIELD

The present disclosure relates, in general, to wells, and, in particular, to a system, method, and apparatus for performing a hydraulic pressure sweep of fluids in a well.

BACKGROUND

At various phases during fluid production from wells, such as hydrocarbon or oil and gas wells, pressure within a production zone may drop and various downhole well conditions may introduce obstructions within the wellbore. The pressure drop and obstructions may impede the flow of crude or gas from the production zone. Such conditions may require the deployment of different production and cleanout systems and techniques which are utilized when the well is off production.

SUMMARY

This disclosure provides systems, methods, and apparatuses for performing a hydraulic pressure sweep of fluids in a well.
In a first embodiment, a system for recovering production fluid from a well is provided. The system includes a return string for receiving fluid from a lateral section of a wellbore. The return string is configured to extend from a surface of a terrestrial formation through at least a portion of the wellbore. The system also includes an injection string for communicating fluid from the surface of the terrestrial formation to the lateral section of the wellbore. The injection string includes a first injection string section located at a distal end of the injection string and for communicating fluid through at least a portion of the lateral section of the wellbore. The first injection string section includes a first cross-sectional area. The injection string includes a second injection string section located at a proximal end of the injection string and for communicating fluid from the surface of the terrestrial formation to the first injection string section. The second injection string section includes a second cross-sectional area that is less than the first cross-sectional area.
In a second embodiment, a method for removing an obstruction in a wellbore using a production fluid recovery system is provided. The method includes extending an injection string from a surface of a terrestrial formation and through at least a portion of the lateral section of the wellbore to communicate fluid to the lateral section of the wellbore. The injection string includes a first injection string section located at a distal end of the injection string and for communicating fluid through at least a portion of the lateral section of the wellbore. The first injection string section includes a first cross-sectional area. The injection string includes a second injection string section located at a proximal end of the injection string and for communicating fluid from the surface of the terrestrial formation to the first injection string section. The second injection string section includes a second cross-sectional area that is less than the first cross-sectional area. The method also includes communicating fluid through injection string. The further includes detecting an obstruction within the wellbore. In addition, the method includes injecting a treatment fluid into the injection string in response to detecting the obstruction in the wellbore, wherein the treatment fluid injected into the injection string is to remove at least some of the obstruction from the wellbore and achieve an underbalance low pressure circulation stream in the lateral section of the wellbore.
In a third embodiment, a system for recovering production fluid from a well is provided. The system includes a return string for receiving fluid from a lateral section of a wellbore. The return string is configured to extend from a surface of a terrestrial formation through at least a portion of the wellbore. The system also includes an injection string for communicating fluid from the surface of the terrestrial formation to the lateral section of the wellbore. The injection string includes a first injection string section located at a distal end of the injection string and for communicating fluid through at least a portion of the lateral section of the wellbore. The first injection string section includes a first cross-sectional area. The injection string includes a second injection string section located at a proximal end of the injection string and for communicating fluid from the surface of the terrestrial formation to the first injection string section. The second injection string section includes a second cross-sectional area that is less than the first cross-sectional area. The system further includes a packer positioned within the lateral section of the wellbore to fluidly divide the lateral section of the wellbore into a first lateral section and a second lateral section. The packer includes an aperture that receives the first injection string section from the second lateral section and permits the first injection string section to extend into the first lateral section.
Other technical features may be readily apparent to one skilled in the art from the following figures, descriptions, and claims.
Before undertaking the DETAILED DESCRIPTION below, it may be advantageous to set forth definitions of certain words and phrases used throughout this patent document. Unless otherwise specified, any use of any form of the terms “connect,” “engage,” “couple,” “attach,” or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Reference to up or down will be made for purposes of description with “up,” “upper,” “upward,” “proximal,” or “upstream” meaning toward the surface of the wellbore and with “down,” “lower,” “downward,” “distal,” or “downstream” meaning toward the terminal end of the well, regardless of the wellbore orientation. The term “zone” or “pay zone” as used herein refers to separate parts of the wellbore designated for treatment or production and may refer to an entire hydrocarbon formation or separate portions of a single formation such as horizontally or vertically spaced portions of the same formation. The term “seat” as used herein may be referred to as a ball seat, but it is understood that seat may also refer to any type of catching or stopping device for an obturating member or other member sent through a work string fluid passage that comes to rest against a restriction in the passage. The term “or” is inclusive, meaning and/or. The phrase “associated with,” as well as derivatives thereof, means to include, be included within, interconnect with, contain, be contained within, connect to or with, couple to or with, be communicable with, cooperate with, interleave, juxtapose, be proximate to, be bound to or with, have, have a property of, have a relationship to or with, or the like. The phrases “at least one of and” one or more of when used with a list of items, means that different combinations of one or more of the listed items may be used, and only one item in the list may be needed. For example, “at least one of: A, B, or C” and “one or more of: A, B, or C includes any of the following combinations: A, B, C, A and B, A and C, B and C, and A and B and C.
Moreover, with respect to electronics, the term “couple” and its derivatives refer to any direct or indirect communication between two or more elements, whether or not those elements are in physical contact with one another. The terms “transmit,” “receive,” and “communicate,” as well as derivatives thereof, encompass both direct and indirect communication. The term “controller” means any device, system or part thereof that controls at least one operation. Such a controller may be implemented in hardware or a combination of hardware and software and/or firmware. The functionality associated with any particular controller may be centralized or distributed, whether locally or remotely. Various functions described below can be implemented or supported by one or more computer programs, each of which is formed from computer readable program code and embodied in a computer readable storage medium. The terms “application” and “program” refer to one or more computer programs, software components, sets of instructions, procedures, functions, objects, classes, instances, related data, or a portion thereof adapted for implementation in a suitable computer readable program code. The phrases “computer readable program code” and “executable instruction” includes any type of computer code, including source code, object code, and executable code. The phrase “computer readable medium” and “computer-readable storage medium” includes any type of medium capable of being accessed by a computer or a processor, such as read only memory (ROM), random access memory (RAM), a hard disk drive, a compact disc (CD), a digital video disc (DVD), or any other type of memory. A “non-transitory” computer-readable medium and a “non-transitory” computer-readable storage medium exclude wired, wireless, optical, or other communication links that transport transitory electrical or other signals. A non-transitory, computer-readable medium and a non-transitory, computer-readable storage medium include media where data can be permanently stored and media where data can be stored and later overwritten, such as a rewritable optical disc or an erasable memory device.
The various characteristics mentioned above, as well as other features and characteristics described in more detail below, will be readily apparent to those skilled in the art with the aid of this disclosure upon reading the following detailed description of the embodiments, and by referring to the accompanying drawings. Definitions for other certain words and phrases are provided throughout this patent document. Those of ordinary skill in the art should understand that in many if not most instances, such definitions apply to prior as well as future uses of such defined words and phrases.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of this disclosure and its advantages, reference is now made to the following description, taken in conjunction with the accompanying drawings, in which:

FIG. 1 illustrates a non-limiting, example production fluid recovery system in an operating environment according to certain embodiments of this disclosure;

FIG. 2 illustrates a non-limiting, example method for recovering fluid from a well using a production fluid recovery system according to certain embodiments of this disclosure;

FIG. 3 illustrates another non-limiting, example method for recovering fluid from a well using a production fluid recovery system according to certain embodiments of this disclosure;

FIG. 4 illustrates another non-limiting, example production fluid recovery system in an operating environment according to certain embodiments of this disclosure;

FIG. 5 illustrates another non-limiting, example production fluid recovery system in an operating environment according to certain embodiments of this disclosure;

FIG. 6 illustrates another non-limiting, example production fluid recovery system in an operating environment according to certain embodiments of this disclosure;

FIG. 7 illustrates another non-limiting, example production fluid recovery system in an operating environment according to certain embodiments of this disclosure;

FIG. 8 illustrates a non-limiting, example production fluid recovery system including a surface system according to certain embodiments of this disclosure;

FIG. 9 illustrates another non-limiting, example method for operating a production fluid recovery system and a surface system according to certain embodiments of this disclosure;

FIG. 10 illustrates another non-limiting, example production fluid recovery system in an operating environment according to certain embodiments of this disclosure;

FIG. 11 illustrates another non-limiting, example method for recovering fluid from a well using a production fluid recovery system according to certain embodiments of this disclosure; and

FIG. 12 illustrates a non-limiting, example computer system configured to implement systems and methods for operating a production fluid recovery system and a surface system according to certain embodiments of this disclosure.

DETAILED DESCRIPTION

At various phases during fluid production from wells, such as hydrocarbon or oil and gas wells, it may be necessary to install an artificial lift system to extract fluid from the wellbore to the surface. In some versions, artificial lift systems may deploy enhanced recovery methods such as water flooding, SAGD operations, steam injection, CO₂injection, gas injection, or the like. Enhanced recovery techniques may typically involve either drilling a separate wellbore or using an existing depleted producer well and converting that well into an injector well. A packer may be run on an end of tubing extending into the wellbore to seal off the production casing from the perforations, open hole, or ports in the well. Fluid, steam, CO₂, or natural gas may then be pumped through the tubing and packer into the formation, creating a manufactured pressure increase. Increasing pressure on the formation may push hydrocarbons into offsetting producer wells to be pumped out by an artificial lift to the surface of the well.
An oil well may include a casing and a production pipe disposed within the casing. The casing may have perforations or ports at the bottom end in an oil production zone to allow crude oil to enter through the perforations or ports. The top end of the well may be sealed by a wellhead secured to the casing. The fluid in the well may rise to the natural level within a well annulus between the casing and the production tubing.
Open-hole completions may also be used to complete a casing above the production zone. Fluid from the production zone may flow into the wellbore. Some oil wells may be completed as horizontal wells. These wells consist of a vertical section having a casing cemented in the ground. The wellbore may have a lateral or “horizontal” section that runs along the producing formation. The lateral section may include an open hole, slotted casing, fracturing ports, perforations, or the like. These features may allow formation fluids and gases to flow into a vertical section of the wellbore to subsequently flow or be pumped to the surface.
During the production phase, the production zone pressure may drop off and various downhole well conditions may introduce obstructions within the well bore. The pressure drop and obstructions may impede the flow of crude or gas from the production zone. Such conditions may require the deployment of different production and cleanout systems. One example may include a heel system having a packer system set in the build section of the wellbore between the vertical and lateral sections of the wellbore. Another solution may include a gas lift system having a tail string running to the tail of the lateral section to carry gas to the toe and sweep the lateral section clean of obstructions, pushing formation fluids to the surface.
Cleanout systems may include a mill on the bottom of coiled or conventional tubing that extends from the bottom of the well to the surface. Fluid or inert gasses may be pumped down the tubing to rotate the bit or mill and may create a circulation or stream to carry the obstructions to the surface. Such cleanout system may open the production zone to allow crude oil to flow to the production casing.
FIGS. 1 through 12, discussed below, and the various embodiments used to describe the principles of this disclosure in this patent document are by way of illustration only and should not be construed in any way to limit the scope of the disclosure. Those skilled in the art will understand that the principles of this disclosure may be implemented in any suitably arranged system or environment.
FIG. 1 illustrates a non-limiting, example production fluid recovery system 100 (hereinafter “system 100”) in an operating environment 101 according to certain embodiments of this disclosure. Although certain details will be provided with reference to the system 100 of FIG. 1, it should be understood that other embodiments may include more, less, or different features including one or more features described herein. As shown in FIG. 1, the system 100 may be utilized in an operating environment 101 that includes a wellhead 103, a well 13, and a wellbore 15. The wellhead 103 may be positioned at a surface 17 of a terrestrial formation 19 and may be in fluid communication with the well 13 and the wellbore 15. The wellhead 103 may provide a structural and pressure-containing interface for drilling and production systems and equipment. For example, the wellhead 103 may provide a suspension point and pressure seals for casing strings that extend at least partially through the wellbore to the surface fluid and pressure control equipment. The wellhead 103 may provide fluid communication between surface fluid and pressure control equipment and at least one of the well 13, the wellbore 15, or one or more strings positioned within the wellbore 15. In certain embodiments, the wellhead 103 may include one or more flow channels 105 and one or more ports 107 each associated with at least one the flow channels 105. For example, the wellhead 103 may include a first flow channel 105 a that communicates fluid from the wellbore 15 and a second flow channel 105 b that communicates fluid into the wellbore 15. A first port 107 a may be in fluid communication with the first flow channel 105 a and provide fluid communication from the first flow channel 105 a to surface equipment. A second port 107 b may be in fluid communication with the second flow channel 105 b and provide fluid communication from surface equipment to the second flow channel 105 b.
The wellbore 15 may extend into the well 13 from the surface 17 of the terrestrial formation 19, through the terrestrial formation 19, and to a distal end of the wellbore 15. In certain embodiments, the wellbore 15 may include a vertical section 20 of the wellbore 15 (hereinafter “vertical wellbore”) and lateral section 21 of the wellbore 15 (hereinafter “lateral wellbore”) that extends from the vertical wellbore 20. The lateral wellbore 21 may include fracture ports for ingress and egress of fluids relative to the terrestrial formation 19 adjacent the lateral wellbore 21, while maintaining the integrity of the well. As used herein, the term “vertical wellbore” or “vertical section of a wellbore” may include a section within a well 13 (e.g., a wellbore) that extends from the surface 17 and, generally, has an axis (e.g., a central axis) that extends substantially in the direction of gravity. Also, as used herein, the term “lateral wellbore” or “lateral section of a wellbore” may include a section within the well 13 that, generally, is gradually bent from a substantially vertical axis (e.g., with respect to gravity) into a horizontal axis (e.g., with respect to gravity) to follow a formation. As shown in FIG. 1, the lateral wellbore 21 may include a heal 23 that is proximal relative to the wellbore 15 and a toe 25 that is distal relative to the wellbore 15.
In certain embodiments, the wellbore 15 may include a production casing 37 formed around an interior surface of the wellbore 15 and extending along the vertical wellbore 20. For example, the production casing 37 may be formed around an interior surface of the vertical wellbore 20 and extend from the surface 17 to a kick-off-point (KOP) 22. The KOP 22 may be a vertical section of a wellbore that begins to transition or turn in a lateral direction, such as into a lateral wellbore. In certain embodiments, the production casing 37 may extend further down the wellbore 15 beyond the KOP 22. In certain embodiments, the production casing 37 may open up into a production liner 39 or an open hole. It should be understood that an open hole may be a section of a wellbore that includes no casing and no liner.
The wellbore 15 may include a production liner 39 formed around and extending along the lateral wellbore 21. For example, the production liner 39 may be formed around an interior surface of the lateral wellbore 21 and extend from the KOP 22 or a distal end of the production casing 37 to a distal end of the lateral wellbore 21. As another example, the production liner 39 may be formed around an interior surface of the lateral wellbore 21 and extend from the KOP 22 or a distal end of the production casing 37 to an open hole section of the lateral wellbore 21. As yet another example, the production liner 39 may be formed around an interior surface of the lateral wellbore 21 and extend from a proximal end of the lateral wellbore 21 to a distal end of the lateral wellbore 21 or an open hole section of the lateral wellbore 21.
In certain embodiments, the system 100 may be positioned within the wellbore 15 and utilized to extract production fluid from the well 13 and remove an obstruction within the wellbore 15 (e.g., an annulus of the wellbore 15, a flow channel through a component of the system 100 positioned within the wellbore 15) created during production fluid extraction. The system 100 may generally include a return string 31 and an injection string 41. The return string 31 may be configured to extend from a surface 17 and through at least a portion of the wellbore 15. For example, the return string 31 may extend from the surface 17, through the wellbore 15, and to (e.g., within about 10 meters above, at, or within about 10 meters below) the KOP 22 within the wellbore 15. As another example, the return string 31 may extend from the surface 17, through the wellbore 15, and to (e.g., within about 10 meters above, at, or within about 10 meters below) a fluid surface within the wellbore 15. As yet another example, the return string 31 may extend only through the vertical wellbore 20 and may not extend into the lateral wellbore 21. Alternatively, the return string 31 may extend through only a portion of the lateral wellbore 21.
The return string 31 may be configured to receive fluid from the wellbore 15 and communicate the received fluid there through along a length of the return string 31 to the surface 17. In certain embodiments, the return string 31 may include tubing 33 that extends along a length of the return string 31 (e.g., an entire length of the return string 31) and communicates the received fluid from the wellbore 15 to the surface 17. For example, the return string 31 may receive fluid from the wellbore 15 using one or more apertures through the return string 31 at a distal end or a distal portion of the return string 31. The return string 31 may use the tubing 33 to communicate the received fluid to a proximal end or a proximal portion of the return string 31 to surface fluid and pressure control equipment located at the surface 17 via the first flow channel 105 a of the wellhead 103.
Generally, the distal portion or distal end of the return string 31 may be the portion or end of the return string 31 that is inserted into the wellbore 15 first from the surface 17. Conversely, a proximal portion or proximal end of the return string 31 may be the portion or end of the return string 31 that is located at an opposite end of the return string 31 from the distal portion. Additionally, or alternatively, a proximal portion or proximal end of the return string 31 may be the portion or end of the return string 31 that is inserted into the wellbore 15 last from the surface 17. Additionally, or alternatively, a proximal portion or proximal end of the return string 31 may be the portion or end of the return string 31 that cannot be inserted into the wellbore 15 before the distal portion or the distal end of the return string 31 is inserted into the wellbore from the surface 17.
In certain embodiments, the system 100 may include an artificial lift system 35. An artificial lift system 35 may be used to artificially increase a flow velocity of fluids (e.g., crude oil, water, or natural gas) being extracted from a production well. The artificial lift system 35 may be in fluid communication with the return string 31 and may be used to draw fluid into the tubing 33 of the return string 31. In certain embodiments, an artificial lift system 35 may be a component of the return string 31. For example, as shown in FIG. 1, the artificial lift system 35 may be positioned at a distal end of the return string 31 and may be used to artificially draw fluid from the wellbore 15 into the tubing 33 of the return string 31 and to the surface 17.
In certain embodiments, the artificial lift system 35 may be positioned within the vertical wellbore 20. For example, the artificial lift system 35 may be landed or positioned at a bottom or a distal end of the production casing 37 of the wellbore 15. Additionally, or alternatively, the artificial lift system 35 may be landed or positioned above the production liner 39 of the lateral wellbore 21. As another example, the artificial lift system 35 may be landed or positioned in the vertical wellbore 20 above the KOP 22 adjacent a build section where the production casing 37 turns into the lateral wellbore 21. In certain embodiments, the artificial lift system 35 may be positioned only in the vertical wellbore 20 or may not be positioned in the lateral wellbore 21. Alternatively, the artificial lift system 35 may be position in the lateral wellbore 21, for example, a distance away from a distal end of the lateral wellbore 21.
As described herein, the system 100 may also generally include an injection string 41. The injection string 41 may be configured to extend between the surface 17 and a portion of the wellbore 15. In certain embodiments, the injection string 41 may extend from the surface 17, through the vertical wellbore 20, and through at least a portion of the lateral wellbore 21. For example, the injection string 41 may extend from the surface 17, through the vertical wellbore 20, and into the lateral wellbore 21 at a proximal end or a proximal portion of the lateral wellbore 21. Additionally, or alternatively, the injection string 41 may extend from the surface 17, through the vertical wellbore 20, and into the lateral wellbore 21 at a distal end or distal portion of the production casing 37. Additionally, or alternatively, the injection string 41 may extend from the surface 17, through the vertical wellbore 20, and into the lateral wellbore 21 at a proximal end or a proximal portion of the production liner 39. In certain embodiments, the injection string 41 may extend from the surface 17, through the vertical wellbore 20, and into the lateral wellbore 21 at a section of the lateral wellbore 21 that is adjacent to a terrestrial formation 19 containing production fluid.
As another example, the injection string 41 may extend from the surface 17, through the vertical wellbore 20, and into the lateral wellbore 21 at a distal end or distal portion of the lateral wellbore 21. Additionally, or alternatively, the injection string 41 may extend from the surface 17, through the vertical wellbore 20, and into the lateral wellbore 21 at a distal end or a distal portion of the production liner 39. Additionally, or alternatively, the injection string 41 may extend from the surface 17, through the vertical wellbore 20, and into the lateral wellbore 21 at a proximal end of an open-hole section of the lateral wellbore 21.
The injection string 41 may be configured to receive fluid from the surface 17, communicate the received fluid there through along a length of the injection string 41 to a position or location within the wellbore 15. In certain embodiments, the injection string 41 may include tubing 42 that extends along a length of the injection string 41 (e.g., an entire length of the injection string 41) and communicates received fluid from the surface 17, along at least a portion of the wellbore 15, to a position or location within the wellbore 15. For example, the injection string 41 may receive fluid at a proximal end or a proximal portion of the injection string 41 from surface fluid and pressure control equipment, via the second flow channel 105 b of the wellhead 103, and communicate the received fluid through the tubing 42 along at least a portion of the wellbore 15 to a distal end or a distal portion of the injection string 41. The injection string 41 may inject the communicated fluid from the tubing 42 into the wellbore 15 (e.g., an annulus of the wellbore 15) using one or more apertures through the injection string 41 that are located at a distal end or a distal portion of the injection string 41. In certain embodiments, when the injection string 41 extends through at least a portion of the lateral wellbore 21, the injection string 41 may receive fluid from the surface 17, communicate the received fluid through the tubing 42, and inject the communicated fluid at a section within the lateral wellbore 21. In certain embodiments, the injection string 41 may use the tubing 42 to communicate fluid including at least one of water, injection fluid, treatment fluid, oil, an acidic fluid, or the like.
In certain embodiments, a distal end of the injection string 41 or an aperture through the injection string 41 to inject fluid into the wellbore 15 may be separated by a distance (e.g., a wellbore axial distance) from an aperture through the return string 31, described herein, positioned within the wellbore 15 and that receives fluid from the wellbore 15. For example, an aperture through the injection string 41 to inject fluid into the wellbore 15 may be positioned within the lateral wellbore 21 so that an aperture through the injection string 41 is separated by a distance from an aperture through a return string 31 located within the vertical wellbore 20. A closest distance between a distal end of the injection string 41 or an aperture through the injection string 41 to inject fluid into the wellbore 15 and an aperture through the return string 31, described herein, may be great enough to permit fluid provided by the injection string 41 into the wellbore 15 (e.g., the lateral wellbore 21) to receive production fluid from an adjacent terrestrial formation (e.g., a terrestrial formation adjacent the lateral wellbore 21) before being received by the return string 31.
Generally, the distal portion or distal end of the injection string 41 may be the portion or end of the return string 31 that is inserted into the wellbore 15 first from the surface 17. Conversely, a proximal portion or proximal end of the injection string 41 may be the portion or end of the injection string 41 that is located at an opposite end of the injection string 41 from the distal portion. Additionally, or alternatively, a proximal portion or proximal end of the injection string 41 may be the portion or end of the injection string 41 that is inserted into the wellbore 15 last from the surface 17. Additionally, or alternatively, a proximal portion or proximal end of the injection string 41 may be the portion or end of the injection string 41 that cannot be inserted into the wellbore 15 before the distal portion or distal end of the injection string 41 is inserted into the wellbore from the surface 17.
In certain embodiments, the injection string 41 may include a first injection string section 43 and a second injection string section 45. The first injection string section 43 may be positioned along a distal portion of the injection string 41 or may extend along a portion of the injection string 41 from a distal end of the injection string 41. The injection string 41 may be configured so that the first injection string section 43 extends at least partially into the lateral wellbore 21. The first injection string section 43 may include a first cross-sectional area and may use the first cross-sectional area to communicate fluid there through. For example, a first portion of the tubing 41 that is located along the first injection string section 43 may include the first cross-sectional area that is utilized to communicate fluid there through.
The second injection string section 45 may be positioned along a proximal portion of the injection string 41 or may extend along a portion of the injection string 41 from a proximal end of the injection string 41. The injection string 41 may be configured so that the second injection string section 45 follows behind the first injection string section 43 as the first injection string section 43 extends at least partially into the lateral wellbore 21. In certain embodiments, the injection string 41 may be configured so that when the first injection string section 43 is positioned within the lateral wellbore 21, the second injection string section 45 is positioned within the vertical wellbore 20. The second injection string section 45 may include a second cross-sectional area and may use the second cross-sectional area to communicate fluid there through and into the first injection string section 43. For example, a second portion of the tubing 42 that is located along the second injection string section 45 may include a second cross-sectional area that is utilized to communicate the fluid there through and into the first injection string section 43 utilizing the first cross-sectional area.
In certain embodiments, the injection string 41 may be divided between the first injection string section 43 and the second injection string section 45 so that a length of the injection string 41 includes the first injection string section 43 and a remaining length of the injection string 41 includes the second injection string section 45. In certain embodiments, the first injection string section 43 extends along half of the length of the injection string 41 and the second injection string section 45 extends along the other half of the length of the injection string 41. Alternatively, the first injection string section 43 extends along a length of the injection string 41 that is great than or less than half the length of the injection string 41 and the second injection string section 45 extends along the remaining length of the injection string 41. In certain embodiments, the first injection string section 43 and the second injection string section 45 together do not extend along the entire length of the injection string 41.
In certain embodiments, the first cross-sectional area of the first injection string section 43 may be greater than the second cross-sectional area of the second injection string section 45. For example, a cross-sectional area through the injection string 41 may increase from the second cross-section area to the first cross-sectional area along the length of the injection string 41 from the second injection string section 45 to the first injection string section 43. As another example, the tubing 42 extending along the length of the second injection string section 45 may include the second cross-sectional area. As the tubing 42 transitions along the injection string 41 from the second injection string section 45 to the first injection string section 43, the cross-section area of the tubing 42 increases from the second cross-sectional area to the first cross-sectional area. In certain embodiments, when the first injection string section 43 is positioned within the lateral wellbore 21, the first cross-sectional area of the first injection string section 43 may reduce a cross-sectional area of an annulus between the first injection string section 43 and a wall of the lateral wellbore 21 relative the second cross-sectional area of the second injection string section 45. In addition, when the second injection string section 45 is within the vertical wellbore 20 and the first injection string section 43 is located within the lateral wellbore 21, the second cross-sectional area of the second injection string section 45 may form a restriction or friction within the vertical wellbore 20 to counteract hydrostatic pressure from a weight of fluid inside the first injection string section 43.
In certain embodiments, fluid communicating through the injection string 41 may experience or receive a pressure drop as fluid transitions from the second injection string section 45 to the first injection string section 43. For example, as fluid communicates from the second injection string section 45 to the first injection string section 43, the cross-sectional area of the injection string 41 transitions from the second cross-sectional area to the first cross-sectional area and causes the fluid to receive a pressure drop from the second injection string section 45 to the first injection string section 43. In certain embodiments, the pressure drop may include at least about a 10% pressure drop, at least about a 20% pressure drop, at least about a 30% pressure drop, at least about a 40% pressure drop, at least about a 50% pressure drop, at least about a 60% pressure drop, at least about a 70% pressure drop, at least about a 80% pressure drop, or at least about a 90% pressure drop. In some preferred embodiments, the pressure drop may be between about a 40% pressure drop and about a 60% pressure drop.
A production fluid recovery system, such as the system 100, that includes an injection string 41 that transitions from a second cross-sectional area in the vertical wellbore 20 to a larger first cross-sectional area in the lateral wellbore 21 may not require a restriction provided by a mechanical valve that is controlled by a computing system at the surface 17. Additionally, or alternatively, a production fluid recovery system, such as the system 100, that includes an injection string 41 that transitions from a second cross-sectional area in the vertical wellbore 20 to a larger first cross-sectional area in the lateral wellbore 21 may not require a restriction provided by a mechanical valve that is controlled by raising and lowering the injection string within the wellbore 15 and by jets located at a distal end of the injection string.
In certain embodiments, fluid within a terrestrial formation that is adjacent the lateral wellbore 21 may include a formation pressure. When fluid is injected from the first injection string section 43 into the annulus of the lateral wellbore 21, the fluid injected into the annulus of the lateral wellbore 21 may have a working pressure in the annulus of the lateral wellbore 21 that is lower than the formation pressure. This scenario is called an underbalanced circulation stream. As used herein, the term ‘underbalanced’ circulation may generally refer to a circulation of gas or fluid inside a wellbore that achieves a working pressure (e.g., a pump pressure or hydrostatic pressure) that is a lower pressure than the formation pressure adjacent the wellbore. Such circulation may be achieved by mechanically drawing the hydrostatic pressure off the annulus of the lateral wellbore 21. Underbalanced circulation also may be achieved by reducing the density of the circulation material with gas or lower density fluid. By creating an underbalanced circulation stream through the lateral wellbore 21, the system 100 may reduce degradation of the integrity of the lateral wellbore 21 and may improve or optimize production from the toe 25 to the heal 23.
In certain embodiments, the underbalanced circulation stream may have an injection pressure in the lateral wellbore that is at least about 100 pounds per square inch (psi) below the formation pressure, at least about 200 psi below the formation pressure, at least about 300 psi below the formation pressure, at least about 400 psi below the formation pressure, or at least about 450 psi below the formation pressure. Additionally, or alternatively, the underbalanced circulation stream may have a high velocity from the lateral wellbore toward the vertical wellbore 20 or the artificial lift system 35. For example, the underbalanced circulation stream may have a velocity from the lateral wellbore toward the vertical wellbore 20 or the artificial lift system 35 that is at least about 50 feet per minute (fpm), at least about 100 fpm, or at least about 150 fpm. Such underbalanced circulation streams may prevent clogging of the lateral wellbore 21 and provide more predictable flow toward the vertical wellbore 20 or the artificial lift system 35.
In some embodiments, the return string 31 may send fluid to the surface 17 and reduce a hydrostatic pressure of fluid in the lateral wellbore 21. The artificial lift system 35 may include a fluid volumetric capacity to induce turbulent or non-laminar flow of fluid through the annulus of the lateral wellbore 21. For example, the return string 31 may be a production string for returning production fluid from the wellbore 15, such that substantially no injected fluid from the injection string 41 enters the artificial lift system 35 of the production string without first completely or at least partially mixing with the production fluid received in the annulus of lateral wellbore 21 from the adjacent terrestrial formation.
As shown in FIG. 1, the system 100 may include a return string 31 and an injection string 41 that extend in a parallel orientation with each other through at least a portion of the wellbore 15. In some embodiments, the return string 31 may be positioned outside of the injection string 41. For example, the return string 31 may be positioned outside of the injection string 41 and adjacent the injection string 41, so that an outer surface of the injection string 41 faces an inner surface of the return string 31 (e.g., so that the return string 31 and the injection string 41 are concentric, so that the injection string 41 is nested within the return string 31 but is not concentric with the return sting 31). As another example, the return string 31 may be positioned outside of the injection string 41 and adjacent the injection string 41, so that an outer surface of the return string 31 faces an outer surface of the injection string 41 (e.g., so that the return string 31 and the injection string 41 are not concentric, so that the injection string 41 is not nested within the return string 31).
In certain embodiments, the return string 31 and the injection string 41 may be coupled together (e.g., forming a dual string configuration) and run into the wellbore 15 together or at the same time. Alternatively, the injection string 41 may be independent of the return string 31 and run into the wellbore 15 separately from the return string 31. The system 100 may include a surface injection pump 47 for the injection string 41 to control a flow rate of at least one of the injected fluid flowing into the injection string 41, the injected fluid flowing through the injection string 41, or the injected fluid injecting out of the injection string 41 and into the lateral wellbore 21. The relative geometries of the injection string 41 (e.g., the first injection string section 43, the first cross-sectional area of the first injection string section 43) and the lateral wellbore 21 (e.g., a cross-section area of the lateral wellbore 21) may control a pressure applied by the flow rate through the injection string 41. Alternatively, the system 100 may, for example, not utilize a surface injection pump 47 or may not control a flow rate of the injected fluid flowing into the injection string 41, flowing through the injection string 41, or injecting out of the injection string 41 and into the lateral wellbore 21. Similarly, in some examples, the system 100 may not include varying a density of the injection fluid. Additionally, or alternatively, at least one of the return string 31 (e.g., the tubing 33) or the injection string 41 (e.g., tubing 42) may include conventional tubing or may not include Venturi-style tubing.
FIG. 2 illustrates a non-limiting, example method 200 for recovering fluid from a well 13 using a production fluid recovery system 100 according to certain embodiments of this disclosure. Although certain details will be provided with reference to the method 200 of FIG. 2, it should be understood that other embodiments may include more, less, or different method steps including steps described with respect to other methods provided herein. At step 201, a return string 31 of the system 100 may extend from a surface 17 of a terrestrial formation 19 through at least a portion of a wellbore 15. For example, the return string 31 may extend from the surface 17, through the wellbore 15, and to (e.g., within about 10 meters above, at, or within about 10 meters below) the KOP 22 within the wellbore 15. As another example, the return string 31 may extend from the surface 17, through the wellbore 15, and to (e.g., within about 10 meters above, at, or within about 10 meters below) a fluid surface within the wellbore 15. As yet another example, the return string 31 may extend only through the vertical wellbore 20 and may not extend into the lateral wellbore 21. Alternatively, the return string 31 may extend through only a portion of the lateral wellbore 21.
Additionally, or alternatively, an artificial lift system 35 may be positioned within the wellbore 15. In certain embodiments, instead of a return string 31 extending into the wellbore 15, an artificial lift system 35 may be positioned within the wellbore 15 to draw fluid within the wellbore 15 to the surface 17. In certain embodiments, when the return string 31 extends through the wellbore 15, an artificial lift system 35 may also be positioned within the wellbore 15. For example, an artificial lift system 35 may be a component of the return string 31 and may be positioned at a distal end or a distal portion of the return string 31 so that when the return string 31 extends through the wellbore 15, the artificial lift system 35 is positioned within the wellbore 15.
An artificial lift system 35 may be utilized to artificially increase a flow velocity of fluids from the wellbore 15. For example, an artificial lift system 35 may be utilized to artificially increase a flow velocity of fluids (e.g., crude oil, water, or natural gas) being extracted from a production well. As another example, an artificial lift system 35 may be utilized to artificially increase a flow velocity of fluids (e.g., treatment fluid, injection fluid) within the lateral wellbore 21. The artificial lift system 35 may be in fluid communication with the return string 31 and may be used to draw fluid into the tubing 33 of the return string 31.
In certain embodiments, the artificial lift system 35 may be positioned within the vertical wellbore 20. For example, the artificial lift system 35 may be landed or positioned at a bottom or a distal end of the production casing 37 of the wellbore 15. Additionally, or alternatively, the artificial lift system 35 may be landed or positioned above the production liner 39 of the lateral wellbore 21. As another example, the artificial lift system 35 may be landed or positioned in the vertical wellbore 20 above the KOP 22 adjacent a build section where the production casing 37 turns into the lateral wellbore 21. In certain embodiments, the artificial lift system 35 may be positioned only in the vertical wellbore 20 or may not be positioned in the lateral wellbore 21. Alternatively, the artificial lift system 35 may be position in the lateral wellbore 21, for example, a distance away from a distal end of the lateral wellbore 21.
At step 203, an injection string 41 of the system 100 may extend through the wellbore 15. In certain embodiments, the injection string 41 may extend between the surface 17 and a portion of the wellbore 15. In certain embodiments, the injection string 41 may extend from the surface 17, through the vertical wellbore 20, and through at least a portion of the lateral wellbore 21. For example, the injection string 41 may extend from the surface 17, through the vertical wellbore 20, and into the lateral wellbore 21 at a proximal end or a proximal portion of the lateral wellbore 21. Additionally, or alternatively, the injection string 41 may extend from the surface 17, through the vertical wellbore 20, and into the lateral wellbore 21 at a distal end or distal portion of the production casing 37. Additionally, or alternatively, the injection string 41 may extend from the surface 17, through the vertical wellbore 20, and into the lateral wellbore 21 at a proximal end or a proximal portion of the production liner 39. In certain embodiments, the injection string 41 may extend from the surface 17, through the vertical wellbore 20, and into the lateral wellbore 21 at a middle portion of the lateral wellbore 21.
As another example, the injection string 41 may extend from the surface 17, through the vertical wellbore 20, and into the lateral wellbore 21 at a distal end or distal portion of the lateral wellbore 21. Additionally, or alternatively, the injection string 41 may extend from the surface 17, through the vertical wellbore 20, and into the lateral wellbore 21 at a distal end or a distal portion of the production liner 39. Additionally, or alternatively, the injection string 41 may extend from the surface 17, through the vertical wellbore 20, and into the lateral wellbore 21 at a proximal end of an open-hole section of the lateral wellbore 21.
At step 205, the system 100 may deliver fluid (e.g., injection fluid), through the injection string 41, into the wellbore 15. In certain embodiments, the injection string 41 may receive fluid at the surface 17 and communicate the received fluid there through along a length of the injection string 41 to a position or location within the lateral wellbore 21. In certain embodiments, the injection string 41 may include tubing 42 that extends along a length of the injection string 41 (e.g., an entire length of the injection string 41) and communicates received fluid from the surface 17, along at least a portion of the wellbore 15, to a position or location within the wellbore 15. For example, the injection string 41 may receive fluid at a proximal end or a proximal portion of the injection string 41 from surface fluid and pressure control equipment, via the second flow channel 105 b of the wellhead 103, and communicate the received fluid through the tubing 42 along at least a portion of the wellbore 15 to a distal end or a distal portion of the injection string 41. The injection string 41 may inject the communicated fluid from the tubing 42 into the wellbore 15 (e.g., an annulus of the wellbore 15) using one or more apertures through the injection string 41 that are located at a distal end or a distal portion of the injection string 41. In certain embodiments, the injection string 41 may use the tubing 42 to communicate fluid including at least one of water, injection fluid, treatment fluid, oil, an acidic fluid, or the like.
In certain embodiments, the injection string 41 may include a first injection string section 43 and a second injection string section 45. The first injection string section 43 may be positioned along a distal portion of the injection string 41 or may extend along a portion of the injection string 41 from a distal end of the injection string 41. The injection string 41 may be configured so that the first injection string section 43 extends at least partially into the lateral wellbore 21. The first injection string section 43 may include a first cross-sectional area and may use the first cross-sectional area to communicate fluid there through. For example, a first portion of the tubing 41 that is located along the first injection string section 43 may include the first cross-sectional area that is utilized to communicate the fluid there through.
The second injection string section 45 may be positioned along a proximal portion of the injection string 41 or may extend along a portion of the injection string 41 from a proximal end of the injection string 41. The injection string 41 may be configured so that the second injection string section 45 follows behind the first injection string section 43 as the first injection string section 43 extends at least partially into the lateral wellbore 21. In certain embodiments, the injection string 41 may be configured so that when the first injection string section 43 is positioned within the lateral wellbore 21, the second injection string section 45 is positioned within the vertical wellbore 20. The second injection string section 45 may include a second cross-sectional area and may use the second cross-sectional area to communicate fluid there through and into the first injection string section 43. For example, a second portion of the tubing 42 that is located along the second injection string section 45 may include a second cross-sectional area that is utilized to communicate the fluid there through and into the first injection string section 43.
In certain embodiments, the first cross-sectional area of the first injection string section 43 may be greater than the second cross-sectional area of the second injection string section 45. For example, a cross-sectional area through the injection string 41 may increase from the second cross-section area to the first cross-sectional area along the length of the injection string 41 from the second injection string section 45 to the first injection string section 43. As another example, the tubing 42 extending along the length of the second injection string section 45 may include the second cross-sectional area. As the tubing 42 transitions along the injection string 41 from the second injection string section 45 to the first injection string section 43, the cross-section area of the tubing 42 increases from the first cross-sectional area to the second cross-sectional area. In certain embodiments, when the first injection string section 43 is positioned within the lateral wellbore 21, the first cross-sectional area of the first injection string section 43 may reduce a cross-sectional area of an annulus between the first injection string section 43 and a wall of the lateral wellbore 21 relative the second cross-sectional area of the second injection string section 45. In addition, when the second injection string section 45 is within the vertical wellbore 20 and the first injection string section 43 is located within the lateral wellbore 21, the second cross-sectional area of the second injection string section 45 may form a restriction or friction within the vertical wellbore 20 to counteract hydrostatic pressure from a weight of fluid inside the first injection string section 43.
At step 207, the system 100 may receive, through the return string 31, fluid from the wellbore 15. For example, the return string 31 may receive fluid from the wellbore 15 and communicate the received fluid there through along a length of the return string 31 to the surface 17. In certain embodiments, the return string 31 may include tubing 33 that extends along a length of the return string 31 (e.g., an entire length of the return string 31) and communicates the received fluid from the wellbore 15 to the surface 17. For example, the return string 31 may receive fluid from the wellbore 15 using one or more apertures through the return string 31 at a distal end or a distal portion of the return string 31. The return string 31 may use the tubing 33 to communicate the received fluid through a proximal end or a proximal portion of the return string 31 to surface fluid and pressure control equipment located at the surface 17 by way of the first flow channel 105 a of the wellhead 103.
In certain embodiments, when the system 100 includes an artificial lift system 35, the artificial lift system 35 may draw or artificially increase a flow velocity of fluids (e.g., crude oil, water, or natural gas) being received by the return string 31. For example, the artificial lift system 35 may be in fluid communication with the return string 31 and may draw fluid into the tubing 33 of the return string 31. In certain embodiments, an artificial lift system 35 may be positioned at a distal end of the return string 31 and may artificially draw fluid from the wellbore 15 into the tubing 33 of the return string 31 and to the surface 17.
At step 209, the system 100 may reduce a hydrostatic pressure of fluid within the wellbore 15. For example, as fluid communicates through the injection string 41, the communicating fluid may experience or receive a pressure drop as the fluid transitions from the second injection string section 45 having the smaller second cross-sectional area to the first injection string section 43 having the larger first cross-sectional area. After receiving the pressure drop, the fluid may be injected into the annulus of the lateral wellbore 21 reducing a hydrostatic pressure within the annulus of the lateral wellbore 21. In addition, the return string 31 receiving fluid from the wellbore 15 may also draw pressure off the annulus of the lateral wellbore 21 reducing a hydrostatic pressure within the annulus of the lateral wellbore 21. In certain embodiments, an artificial lift system 35, in cooperation with the return string 31, may artificially draw fluid from the wellbore 15 and artificially draw pressure off pressure from the annulus of the lateral wellbore 21 reducing the hydrostatic pressure within the annulus of the lateral wellbore 21. Additionally, or alternatively, injecting a gas or a low density fluid, through the injection string 41, into the annulus of the lateral wellbore 21 may reducing the hydrostatic pressure within the annulus of the lateral wellbore 21. The above-mentioned embodiments to reduce a hydrostatic pressure of fluid within the wellbore 15 may be used alone or in combination with one or more other embodiments including one or more other embodiments described herein.
At step 211, the system 100 may communicate production fluid from the wellbore 15, through the return string 31 (e.g., a production string, a return sting acting as a production string), and to a surface 17 of a terrestrial formation 19. For example, fluid (e.g., production fluid) within a terrestrial formation 19 that is adjacent the lateral wellbore 21 may include a formation pressure. When the system 100 reduces the hydrostatic pressure within the annulus of the lateral wellbore 21, the hydrostatic pressure or working pressure within the annulus of the lateral wellbore 21 may decrease to a pressure that is below the formation pressure. This scenario is called an underbalanced circulation stream. The pressure drop or differential from the terrestrial formation 19 that is adjacent the lateral wellbore 21 to the annulus of the lateral wellbore 21 may cause production fluid within the terrestrial formation 19 that is adjacent the lateral wellbore 21 to be drawn into the annulus of the lateral wellbore 21. Subsequently, as the return string 31 receives fluid from the wellbore 15, the return string 31 may receive the production fluid from the lateral wellbore 21 and communicate the production fluid to the surface 17. By creating an underbalanced circulation stream through the lateral wellbore 21, the system 100 may reduce degradation of the integrity of the lateral wellbore 21 and may improve or optimize production from the toe 25 to the heal 23.
In some embodiments, the system 100 may include an artificial lift system 35 that has a fluid volumetric capacity to induce turbulent or non-laminar flow of fluid through the annulus of the lateral wellbore 21. When the system 100 includes the artificial lift system 35, the return string 31 may send fluid to the surface 17 and the artificial lift system 35 may draw production fluid from the lateral wellbore 21, such that substantially no injected fluid from the injection string 41 enters the artificial lift system 35 or the return string 31 without first completely mixing or at least partially mixing with the production fluid received in the annulus of lateral wellbore 21 from the adjacent terrestrial formation.
Returning to FIG. 1, as described herein, the injection string 41 may include a first injection string section 43 and a second injection string section 45. In certain embodiments, the first injection string section 43 and the second injection string section 45 may form an injection string 41 that is a single continuous component. In this case, the first injection string section 43 may not detach from or detach and reattach (e.g., a plurality of times) with the second injection string section 45 without physical components of injection string 41 being mechanically broken or damaged.
In certain embodiments, the first injection string section 43 and the second injection string section 45 may be separate components of the injection string 41. In this case, the first injection string section 43 may detach from, attach to, or detach and reattach (e.g., a plurality of times) with the second injection string section 45 without physical components of injection string 41 being mechanically broken or damaged. For example, initially, the first injection string section 43 may not be coupled to the second injection string section 45. The first injection string section 43, while uncoupled to the second injection string section 45, may be inserted into the wellbore 15 so that the first injection string section 43 extends through at least a portion of the wellbore 15. After the first injection string section 43 is inserted into wellbore 15 so that the first injection string section 43 extends through at least a portion of the wellbore 15, the first injection string section 43 may anchor to a position within the wellbore 15. For example, the first injection string section 43 may anchor to a position within the wellbore 15 so that a proximal end of the first injection string section 43 is located within the wellbore 15. In some embodiments, the first injection string section 43 may anchor to a position within the wellbore 15 so that a distal end of the first injection string section 43 is located within the lateral wellbore 21.
Subsequently, after the first injection string section 43 anchors to the position within the wellbore 15, the second injection string section 45 may be inserted into the wellbore 15 so that the second injection string section 45 extends through at least a portion of the wellbore 15. The second injection string section 45 may extend through at least a portion of the wellbore 15 so that the distal end of the second injection string section 45 is positioned at a location of the proximal end of the first injection string section 43 within the wellbore 15. When the distal end of the second injection string section 45 is positioned at the location of the proximal end of the first injection string section 43, the distal end of the second injection string section 45 may couple (e.g., removably coupled, fixedly coupled) or attached (e.g., removably attached, fixedly attached) to the proximal end of the first injection string section 43. When the distal end of the second injection string section 45 couples to the proximal end of the first injection string section 43, the first injection string section 43 and the second injection string section 45 may form a continuous flow path or flow channel sealed from the annulus of the wellbore 15 across the transition from the second injection string section 45 to the first injection string section 43.
In certain embodiments, the second injection string section 45 may be independently inserted into the wellbore 15 so that the second injection string section 45 couples to the first injection string section 43. Alternatively, the second injection string section 45 may couple to the return string 31 (e.g., forming a dual string configuration) so that when the distal end of the second injection string section 45 is inserted into the wellbore 15 so that the second injection string section 45 extend through at least a portion of the wellbore 15, the return string 31 attached to the second injection string section 45 is contemporaneously inserted into the wellbore 15 so that the return string 31 extends through at least a portion of the wellbore 15. When the distal end of the second injection string section 45 is positioned at the location of the proximal end of the first injection string section 43 within the wellbore 15, the distal end of the second injection string section 45 may couple or attach to the proximal end of the first injection string section 43. The return string 31, coupled to the second injection string section 45, may remain in a position to receive fluid from the wellbore 15 through one or more apertures located at a distal end or at a distal portion of the return string 31.
FIG. 3 illustrates a non-limiting, example method 300 for recovering fluid from a well 13 using a production fluid recovery system 100 according to certain embodiments of this disclosure. Although certain details will be provided with reference to the method 300 of FIG. 3, it should be understood that other embodiments may include more, less, or different method steps including steps described with respect to other methods provided herein. FIGS. 4, 5, 6, and 7 illustrates other non-limiting, example production fluid recovery system 100 in an operating environment 101 according to certain embodiments of this disclosure. FIGS. 4, 5, 6, and 7 illustrates the operations or steps described with respect to method 300 illustrated in FIG. 3. Although certain details will be provided with reference to the system 100 of FIGS. 4, 5, 6, and 7 it should be understood that other embodiments may include more, less, or different features including one or more features described herein.
At step 301 and described at least with respect to FIG. 4, a first injection string section 43 of an injection string 41 of the system 100 may extend into a lateral wellbore 21. FIG. 7, described herein, illustrates an example embodiment of a first injection string section 43 extended into a lateral wellbore 21. Turning back to the example embodiment of FIG. 4, a first injection string section 43 may extend into the wellbore 15 and through at least a portion of the wellbore 15. For example, the distal end of the first injection string section 43 may be positioned in the wellbore 15 so that, initially, the distal end of the first injection string section 43 extends through at least a portion of the wellbore 15. Subsequently, a proximal end of the first injection string section 43 may be positioned in the wellbore 15 so that the proximal end of the first injection string section 43 extends through at least a portion of the wellbore 15. In certain embodiments, the injection string 41 may be positioned in the wellbore 15 so that the distal end of the first injection string section 43 extends at least partially through the lateral wellbore 21 while the proximal end of the first injection string section 43 extends through at least some of the vertical wellbore 20.
In addition, as shown in FIG. 4, the proximal end of the first injection string section 43 may couple to a distal end of a working string 401 using an interchange anchor (IA) 403. The IA 403 may removable attached the first injection string section 43 to the working string 401. For example, the IA 403 may include a j-slot on/off latch assembly 405 fixedly attached to the distal end of the working string 401 and a bottom latch assembly 407 fixedly attached to a proximal end of the first injection string section 43. The j-slot on/off latch assembly 405 may be attached to the bottom latch assembly 407 in a locked or secured configuration coupling the first injection string section 43 to the working string 401. With the proximal end of the first injection string section 43 coupled to the distal end of the working string 401, the first injection string section 43 may be inserted into the wellbore 15 using the working string 401 so that first injection string section 43 extends into the lateral wellbore 21.
At step 303 and as illustrated in FIG. 4, the first injection string section 43 of the system 100 may anchor to a fixed position within the wellbore 15. For example, the working string 401 may extend into the wellbore 15 so that the distal end of the first injection string section 43 is within the lateral wellbore 21 and the proximal end of the first injection string section 43 is within the vertical wellbore 20. When the first injection string section 43 is within the lateral wellbore 21 and the proximal end of the first injection string section 43 is within the vertical wellbore 20, the working string 401 may be stationary within the wellbore 15. The IA 403 may also include an anchor assembly 409 positioned at the proximal end of the first injection string section 43 and configured to anchor or secure the first injection string section 43 to a fixed position within the wellbore 15. The IA 403 may also include a swivel 411 that allows the anchor assembly 409 to rotate independently of the first injection string section 43 (e.g., to rotate without causing the first injection string section 43 to rotate).
When the working string 401 is stationary within the wellbore 15, the working string 401 may rotate in a first direction (e.g., clockwise, to the right) causing the anchor assembly 409 to rotate in the first direction and activate a plurality of slips that extend from the anchor assembly 409. When the plurality of slips is activated, the slips may penetrate into the wall of the vertical wellbore 20 (e.g., the production casing 37) and anchor or secure the first injection string section 43 to a fixed position within the wellbore 15. After the first injection string section 43 anchors or secures to the fixed position within the wellbore 15, the working string 401 may lower further into the wellbore 15 to apply a compression force received against the proximal end of the first injection string section 43. It should be understood that the first injection string section 43 may anchor or secure to the fixed position within the wellbore 15 with enough force so that when the working string 401 applies compression force received against the proximal end of the first injection string section 43, the first injection string section 43 remains anchored or secured to the fixed position within the wellbore 15.
After the proximal end of the first injection string section 43 receives the applied compression force from the working string 401, the working string 401 may rotate in a second direction (e.g., a counter-clockwise direction, to the left) unlocking or releasing the j-slot on/off latch assembly 405 from the bottom latch assembly 407. As shown in FIG. 5, after the j-slot on/off latch assembly 405 is unlocked or released from the bottom latch assembly 407, the first injection string section 43 may decouple or detach from working string 401. The working string 401 may be separated from the first injection string section 43 and retrieved from the wellbore 15 to the surface 17.
At step 305 and as illustrated in FIG. 6, a second injection string section 45 of the injection string 41 of the system 100 may be positioned within wellbore 15 so that the second injection string section 45 extends through the wellbore 15. For example, the second injection string section 45 may be positioned in the wellbore 15 so that the second injection string section 45 extends through the vertical wellbore 20. In addition, when the second injection string section 45 extends through the vertical wellbore 20, the distal end of the second injection string section 45 may engage the proximal end of the first injection string section 43 anchored to the fixed positioned within the vertical wellbore 20.
At step 307 and as illustrated in FIG. 6, an end of the second injection string section 45 may couple to an end of an end of the first injection string section 43. For example, the distal end of the second injection string section 45 may include another j-slot on/off latch assembly 601. After the distal end of the second injection string section 45 engages the proximal end of the first injection string section 43, the bottom latch assembly 407 positioned at the proximal end of the first injection string section 43 may engage the other j-slot on/off latch assembly 601. Subsequently, the second injection string section 45 may lower further into the wellbore 15 and apply a compression force on the bottom latch assembly 407 through the other j-slot on/off latch assembly 601. The first injection string section 43 may anchor or secure to the fixed position within the wellbore 15 with enough force so that when the second injection string section 45 applies compression force against the proximal end of the first injection string section 43, the first injection string section 43 remains anchored or secured the fixed position within the wellbore 15.
Subsequently, the second injection string section 45 may rotate in the first direction causing the other j-slot on/off latch assembly 601 to lock or secure with the bottom latch assembly 407 coupling the distal end the second injection string section 45 to the proximal end of the first injection string section. It should be understood that when the other j-slot on/off latch assembly 601 locks or secures with the bottom latch assembly 407 and the distal end the second injection string section 45 is coupled to the proximal end of the first injection string section, the injection string 41 may form a continuous flow path or flow channel sealed from the annulus of the wellbore 15 across the transition from the second injection string section 45 to the first injection string section 43.
At step 309 and as illustrated in FIG. 6, a return string 31 of the system 100 may be positioned within the wellbore and extend through the wellbore 15. Step 309 is at least similar to step 201 of method 200 illustrated in FIG. 2. In certain embodiments, as shown in FIG. 6, the return string 31 and the second injection string section 45 may be coupled together forming a dual string configuration and may run into the wellbore 15 together or at the same time. Additionally, the return string 31 may include another anchor assembly 603. After the second injection string section 45 couples to the first injection string section 43, the other anchor assembly 603 may activate slips that penetrate into the production casing 37 securing the return string 31 to a fixed position within the vertical wellbore 20. When the return string 31 and the second injection string section 45 couple together forming the dual string configuration, the activated slips of the other anchor assembly 603 penetrating into the production casing 37 may secure the return string 31 and the second injection string section 45 to a fixed position within the vertical wellbore 20. In certain embodiments, when the return string 31 includes an artificial lift system 35, the activated slips of the other anchor assembly 603 penetrating into the production casing 37 may secure the return string 31 and the artificial lift system 35 to a fixed position within the vertical wellbore 20.
At step 311 and as illustrated in FIG. 7, the system 100, using the first injection string section 43 coupled to the second injection string section 45, may deliver fluid into the lateral wellbore 21. Step 311 is at least similar to step 205 of method 200 illustrated in FIG. 2. At step 313 and as illustrated in FIG. 7, the system 100, using the return string 31, may receive fluid from the wellbore 15. Step 313 is at least similar to step 207 of method 200 illustrated in FIG. 2. At step 315 and as illustrated in FIG. 7, the system 100 may reduce a hydrostatic pressure of fluid within the lateral wellbore 21. Step 315 is at least similar to step 209 of method 200 illustrated in FIG. 2. At step 317 and as illustrated in FIG. 7, the system 100, through the return string 31, may communicate production fluid from the wellbore 15 to a surface 17 of a terrestrial formation 19. Step 317 is at least similar to step 211 of method 200 illustrated in FIG. 2.
FIG. 8 illustrates a non-limiting, example production fluid recovery system 800 including a surface system 801 according to certain embodiments of this disclosure. Although certain details will be provided with reference to the system 800 and the surface system 801 of FIG. 8, it should be understood that other embodiments may include more, less, or different features including one or more features described herein. For example, the production fluid recovery system 800 may include one or more features or components of the production fluid recovery system 100 described herein. In certain embodiments, one or more of the features or components of the surface system 801, described herein, may be at least a component of the surface fluid and pressure control equipment, described herein.
In certain embodiments, the wellbore 15 (e.g., the lateral wellbore 21, the vertical wellbore 20, the return string 31 positioned within the wellbore 15, the return string 31 in fluid communication with the wellbore 15) may become obstructed or clogged by one or more obstructions when the system 800 is in a producing mode (e.g., when the system 800 is operating to extracting production fluid from the wellbore 15). For example, the wellbore 15 may become obstructed or clogged by various downhole conditions including wax, scaling, calcium buildup, sand bridging, or the like. An obstruction may impede or prevent the flow of production fluid from the wellbore 15 or from a terrestrial formation 19 that is adjacent a wellbore 15. With a conventional system, upon detection of an obstruction, a production mode may cease in order to remove the obstruction. Conversely, the system 800 may remove an obstruction while remaining in a production mode.
As shown in FIG. 8, the system 800 includes a surface system 801. The surface system 801 may be used to control operations of the system 800, process and store received production fluid, control one or more valves and valves, detect an obstruction within the system 800 or within the wellbore 15, and remove an obstruction within the system 800 or within the wellbore 15. The surface system 801 may include a separator system 805. The separator system 805 may receive return fluid and separate the return fluid into components. In certain embodiments, the separator system 805 may separate the return fluid into solids, liquids, and gases. Additionally, or alternatively, the separate system 805 may break down production fluid into hydrocarbons, gas, solids, and water.
In certain embodiments, the separator system 805 may include one or more tanks (e.g., P tanks) that are fluidly coupled to the wellhead 103 through a return line 803. Upon receiving return fluid from the wellbore 15 through the return line 803, the separator system 805 may separate the return fluid into treatment fluid and injection fluid, gas, solids, hydrocarbons, and water. The separator system 805 may also separate the gas from the return fluid in a P tank and distribute the gas into the flow line 804. The separate system 805 may further separate the solids from the return fluid and retain the solids in the P tank for unloading utilizing service equipment. In addition, the separator system 805 may separate the hydrocarbons from the return fluid and distribute the hydrocarbons into the flow line 804 where the hydrocarbons may then cascade into the pay line 809 that feeds into the pay tank 810. The separator system 805 may also separate the fluids from the solids in the return fluid and distribute the fluids into the circulation line 813 that feeds into the circulation system 815. The fluids may include at least one of water, treatment fluid, or injection fluid. The circulation system 815 may include one or more tanks to store the fluids.
The surface system 801 may also include a fluid injection and treatment system 820. The fluid injection and treatment system 820 may be used to inject treatment fluid into injection fluid that is communicated into the wellbore 15 to remove an obstruction within the wellbore 15. When the system 800 is in a production mode, the injection pump 825 may draw fluid from the circulation system 815 through the injection pump suction line 817 and pump the drawn fluid into the injection line 853 so that the fluid is communicated into the wellbore 15 to generate production.
While generating production, an obstruction may develop in the wellbore 15 or the system 800. The fluid injection and treatment system 820 may use a control system 850 (e.g., a SCADA system) to detect an obstruction in the wellbore 15 and implement the appropriate operations to remove or reduce the obstruction. The control system 850 may be in communication with a plurality of sensors distributed throughout the wellbore 15 and throughout the system 800. Monitoring the sensors, the control system 850 may identify that an obstruction exists in the wellbore 15 or in the system 800. The control system 850 may determine a type of obstruction or a location of an obstruction based on a pressure, a fluid velocity, a volumetric flow rate, or a temperature sensed by one or more sensors or based on a location of one or more monitored sensors.
For example, the control system 850 may determine that a substantial amount of wax has accumulated in the return string 31 based on sensor readings within the return string 31 indicating an increased pressure drop across the return string 31 and a reduced volumetric flow rate of production fluid through the return string 31. In response, the control system 850 may at least partially open one or more valves at a boiler inlet line 822 and at least partially close one or more valves along the injection pump suction line 817 downstream from the boiler inlet line 822. In addition, the control system 850 may at least partially open one or more valves at a boiler outlet line 827. Accordingly, fluid drawn by the injection pump 825 from the circulation system 815 may be drawn through the boiler 830 and heated before entering the injection pump 825. Subsequently, the injection pump 825 may inject treatment fluid in the form of hot injection fluid into the wellbore 15 to reduce or remove the wax accumulation in the return string 31 while the system 800 remains in a production mode.
As another example, the control system 850 may detect sand bridging in the wellbore 15 or the system 800 based on sensor readings. With conventional systems, sand bridging is accepted, and upon detection, such systems maintain a production mode until the sand bridging causes a system failure. Once the system fails, service equipment must be used to remove the production equipment and clean out the sand bridging in the wellbore 15 costing significant time, money, and resource. Once sand bridging is removed from the wellbore 15, the production equipment is placed back in the wellbore 15 to resume production.
Conversely, upon detecting sand bridging in the system 800 or the wellbore 15, the control system 850 may increase the pump speed of the injection pump 825, increase power to the artificial lift system 35, and monitor fluid level sensors within the wellbore 15. By increasing the speed of the injection pump 825, increasing the power to the artificial lift system 35, and monitoring the fluid level sensors within the wellbore 15, the control system 850 may increase the fluid level within the wellbore 15 and a flowrate through the lateral wellbore 21 creating an overbalanced circulation system. The overbalanced circulation system may sweep away sand and other solids that have accumulated in the lateral wellbore 21. Subsequently, the control system 850 may reduce the pump speed of the injection pump 825 and the power to the artificial lift system 35 while monitoring fluid level sensors within the wellbore 15 to resume a production mode.
As yet another example, the control system 850 may detect scaling or calcium build-up in the lateral wellbore 21 based on sensor readings. The control system 850 may at least partially open one or more valves on a chemical system outlet line 842 and initiate the operation of a chemical pump 845. The chemical pump 845 may draw chemicals from a chemical storage system 840 through the chemical system outlet line 842 and inject the drawn chemicals into the injection line 853. The injection pump 825 may pump injection fluid through the injection line 853 as the chemical pump 845 injects chemicals into the injection line 853 causing the injection fluid to mix with the chemicals forming a treatment fluid. The chemical pump 845 and the injection pump 825 may pump the treatment fluid through the injection line and into the wellbore 15 to reduce or remove the scaling or calcium built-up in the lateral wellbore 21 while the system 800 remains in a production mode.
As yet another example, the control system 850 may detect scaling or calcium build-up in the lateral wellbore 21 based on sensor readings. The control system 850 may at least partially open one or more valves on an acid chemical storage system outlet line 833. The injection pump 825 may draw acidic chemical fluids from an acid chemical storage system 835 through the acid chemical storage system outlet line 833 and draw injection fluid from the circulation system 815 through the injection pump suction line 817 and mix the acidic chemical fluids with the injection fluid to form a treatment fluid. Subsequently, the injection pump 825 may pump the treatment fluid through the injection line and into the wellbore 15 to reduce or remove the scaling or calcium built-up in the lateral wellbore 21 while the system 800 remains in a production mode.
FIG. 9 illustrates another non-limiting, example method 900 for operating a production fluid recovery system 800 and a surface system 801 according to certain embodiments of this disclosure. Although certain details will be provided with reference to the method 900 of FIG. 9, it should be understood that other embodiments may include more, less, or different method steps including steps described with respect to other methods provided herein. At step 901, an injection string 41 of the system 800 may be positioned in a wellbore 15 and extend into the lateral wellbore 21. Step 901 is at least similar to step 203 of method 200 illustrated in FIG. 2. At step 903, a return string 31 of the system 800 may be positioned within the wellbore 15 and extend through the wellbore 15. Step 903 is at least similar to step 201 of method 200 illustrated in FIG. 2. At step 905, the system 800 may deliver fluid into the lateral wellbore 21 through the injection string 41. Step 905 is at least similar to step 205 of method 200 illustrated in FIG. 2. At step 907, the system 800 may receive fluid from the wellbore 15 through the return string 31. Step 907 is at least similar to step 207 of method 200 illustrated in FIG. 2.
At step 909, the system 800 may detect an obstruction within the wellbore 15. For example, the system 800 may include a control system 850 (e.g., a SCADA system). The control system 850 may be in communication with a plurality of sensors distributed throughout the wellbore 15 and throughout the system 800. Monitoring the sensors, the control system 850 may identify that an obstruction exists in the wellbore 15 or in the system 800. After detecting the obstruction in the wellbore 15, the control system 850 may determine the type of obstruction, the location of the obstruction, and appropriate operations to remove or reduce the obstruction.
At step 911, the system 800 may determine at least one of a type of the detected obstruction or a location of the detected obstruction in the wellbore 15. For example, the control system 850 of the system 800 may determine a type of obstruction or a location of an obstruction based on a pressure, a fluid velocity, a volumetric flow rate, or a temperature sensed by one or more sensors or based on a location of one or more monitored sensors. The obstruction may include wax build-up in the return string 31, sand bridging in the lateral wellbore 21, scaling or calcium accumulation with the wellbore 15, or the like.
At step 913, the system 800 may inject a treatment fluid into the lateral wellbore 21. For example, the control system 850 of the system 800 may modulate one or more valves or pumps and monitor one or more sensors within the system 800 or within the wellbore 15 to inject a treatment fluid that includes at least one of a hot treatment fluid, a chemical treatment fluid, an acidic chemical treatment fluid, or the like. In certain embodiments, the control system 850 may create an overbalanced circulation stream within the wellbore 15 and utilize treatment fluid in the form of high velocity fluid to sweep objects from the lateral wellbore 21. At step 915, the system 800 may reduce a hydrostatic pressure of fluid within the lateral wellbore 21. Step 915 is at least similar to step 209 of method 200 illustrated in FIG. 2. At step 917, the system 800 may communicate production fluid from the wellbore 15 to a surface 17 of a terrestrial formation 19. Step 917 is at least similar to step 211 of method 200 illustrated in FIG. 2.
FIG. 10 illustrates another non-limiting, example production fluid recovery system 1000 in an operating environment 101 according to certain embodiments of this disclosure. Although certain details will be provided with reference to the system 1000 of FIG. 10, it should be understood that other embodiments may include more, less, or different features including one or more features described herein. For example, the production fluid recovery system 1000 may include one or more features or components of the production fluid recovery system 100 or the production fluid recovery system 800 described herein. As shown in FIG. 10, the system 1000 may include the injection string 41 having the first injection string section 43 and the second injection string section 45. The injection string 41 is anchored, using an anchor 1001, to a fixed position within the wellbore 15 so that the second injection string section 45 extends through the vertical wellbore 20 and the first injection string section 43 extends through the lateral wellbore 21. The anchor 1001 may include one or more features of the interchange anchor 403 illustrated in at least FIG. 4. The return string 31 is coupled to the injection string 41 forming a dual string configuration so that the anchor 1001 secures both the injection string 41 and the return string 31 to fixed positions within the wellbore 15. In certain embodiments, the return string 31 includes an artificial lift system 35 to draw fluids from the wellbore 15 into the return string 31.
In addition, the system 1000 may include a cap member 1003 positioned at a distal end of the lateral wellbore 21. The cap member 1003 may form a seal against the walls of the lateral wellbore 21 preventing fluid communication across the cap member 1003. In certain embodiments, the cap member 1003 may be securely fastened to the walls of the lateral wellbore 21 so that the cap member 1003 maintains the seal against the walls the lateral wellbore 21 and prevents fluid communication across the cap member 1003 under pressure differentials as described herein to retrieve production fluid from adjacent terrestrial formations.
In certain embodiments, the first injection string section 43 may include an annular packer 1005 and an outflow control valve 1007. The annular packer 1005 may form a seal at a position within the wellbore 15 while permitting the injection string 41 to pass through the seal. As shown in FIG. 10, the annular packer 1005 may be positioned around the first injection string section 43 and may form a seal against the walls of the lateral wellbore 21. Thus, the annular packer 1005 may fluidly divide the lateral wellbore 21 into a first or distal lateral wellbore section 1009 and a second or proximal lateral wellbore section 1011. The first lateral wellbore section 1009 may be sealed between the annular packer 1005 and the cap member 1003. A distal portion of the first injection string section 43 may extend through the annular packer 1005 and into the first lateral wellbore section 1009. The distal portion of the first injection string section 43 that extends into the first lateral wellbore section 10090 may include one or more apertures to inject fluid into the lateral wellbore 21.
The outflow control valve 1007 may be positioned along the first injection string section 43 and reside in the second lateral wellbore section 1011. In certain embodiments, the outflow control valve 1007 may be positioned against or near the annular packer 1005. The outflow control valve 1007 may modulate or control a volumetric flow rate of fluid that is injected into the lateral wellbore 21 from the injection string 41. For example, the outflow control valve 1007 may modulate between a fully open position and a fully closed position to achieve a specified volumetric flow rate of fluid injecting into the first lateral wellbore section 1009 through the apertures of the first injection string section 43. When the outflow control valve 1007 is in an open position, fluid may be pumped through the first injection string section 43 and into the first lateral wellbore section 1009 through the one or more apertures of the first injection string section 43. The outflow control valve 1007 may modulate or control the volumetric flow rate of fluid injecting into the first lateral wellbore section 1009 and form a hydrostatic pressure within the first lateral wellbore section 1009 that is greater than a formation pressure of the adjacent terrestrial formation 19. The pressure differential between the first lateral wellbore section 1009 and the adjacent terrestrial formation 19 may force production fluid away from the first lateral wellbore section 1009 and into the underbalanced circulation stream in the second lateral wellbore section 1011. Subsequently, production fluid that is received by the underbalanced circulation stream in the second lateral wellbore section 1011 may be drawn off by an artificial lift system 35 and into the return string 31.
As another example, the outflow control valve 1007 may include one or more apertures 1008 through the first injection string section 43 that are located in the second lateral wellbore section 1011. The apertures 1008 may be configured to inject fluid from the first injection string section 43 directly into the second lateral wellbore section 1011. The outflow control valve 1007 may modulate or control both the volumetric flow rate of fluid injecting from the first injection string section 43 into the first lateral wellbore section 1009 and the volumetric flow rate of fluid injecting from the first injection string section 43 into the second lateral wellbore section 1011 through the one or more apertures 1008. For example, the outflow control valve 1007 may permit most of the fluid communicating through the first injection string section 43 to be injected into the first lateral wellbore section 1009 and the remaining fluid to be injected into the second lateral wellbore section 1011.
The outflow control valve 1007 may modulate or control the volumetric flow rate of fluid injecting into the first lateral wellbore section 1009 and form a hydrostatic pressure within the first lateral wellbore section 1009 that is greater than a formation pressure of the adjacent terrestrial formation 19. The pressure differential between the first lateral wellbore section 1009 and the adjacent terrestrial formation 19 may force production fluid away from the first lateral wellbore section 1009. The outflow control valve 1007 may also modulate or control the volumetric flow rate of fluid injecting into the second lateral wellbore section 1011 and form a hydrostatic pressure within the second lateral wellbore section 1011 that is less than a formation pressure of the adjacent terrestrial formation 19. The outflow control valve 1007 may also control the volumetric flow rate of fluid injecting into the second lateral wellbore section 1011 to achieve a underbalanced circulation stream in the second lateral wellbore section 1011. Thus, production fluid in the terrestrial formation 19 may be forced away from the first lateral wellbore section 1009 and drawn into the second lateral wellbore section 1011 due to the lower hydrostatic pressure and underbalanced circulation stream. Subsequently, production fluid that is received by the underbalanced circulation stream in the second lateral wellbore section 1011 may be drawn off by an artificial lift system 35 and into the return string 31.
FIG. 11 illustrates another non-limiting, example method 1100 for recovering fluid from a well 13 using a production fluid recovery system 1000 according to certain embodiments of this disclosure. Although certain details will be provided with reference to the method 1100 of FIG. 11, it should be understood that other embodiments may include more, less, or different method steps including steps described with respect to other methods provided herein. At step 1101, a return string 1031 of the system 1000 may be positioned within the wellbore 15 and extend through the wellbore 15. Step 1101 is at least similar to step 201 of method 200 illustrated in FIG. 2.
At step 1103, the system 1000 fluidly divides an annulus of the lateral wellbore 21 into a first lateral wellbore section 1009 (e.g., a proximal section of the lateral wellbore 21) and a second lateral wellbore section 1011 (e.g., a distal section of the lateral wellbore 21). For example, the first injection string section 43 may include an annular packer 1005. The annular packer 1005 may form a seal at a position within the wellbore 15. The annular packer 1005 may be positioned around the first injection string section 43 and may form a seal against the walls of the lateral wellbore 21. Thus, the annular packer 1005 may fluidly divide the lateral wellbore 21 into a first or distal lateral wellbore section 1009 and a second or proximal lateral wellbore section 1011. In certain embodiments, the first lateral wellbore section 1009 may be sealed between the annular packer 1005 and a cap member 1003 positioned at a distal end of the lateral wellbore 21 or at a toe 25 of the lateral wellbore 21.
At step 1105, an injection string 41 of the system 1000 may be positioned within the lateral wellbore 21 and extend through the second lateral wellbore section 1011 and into the first lateral wellbore section 1009. For example, as described herein, the first injection string section 43 may include an annular packer 1005. The annular packer 1005 may form a seal at a position within the wellbore 15 while permitting the injection string 41 to pass through the seal. The annular packer 1005 may be positioned around the first injection string section 43 and may form a seal against the walls of the lateral wellbore 21. Thus, the annular packer 1005 fluidly dividing the lateral wellbore 21 into a first or distal lateral wellbore section 1009 and a second or proximal lateral wellbore section 1011 may permit a distal portion of the first injection string section 43 to extend through the annular packer 1005 and into the first lateral wellbore section 1009. In certain embodiments, the distal portion of the first injection string section 43 that extends into the first lateral wellbore section 1009 may include one or more apertures to inject fluid into the lateral wellbore 21.
At step 1107, the system 1000 may communicate fluid, through the injection string 41, into the first lateral wellbore section 1009. The first injection string section 43 may include an outflow control valve 1007. The outflow control valve 1007 may be positioned along the first injection string section 43 and reside in the second lateral wellbore section 1011. In certain embodiments, the outflow control valve 1007 may be positioned against or near the annular packer 1005. The outflow control valve 1007 may modulate between a fully open position and a fully closed position to achieve a specified volumetric flow rate of fluid injecting into the first lateral wellbore section 1009 through the apertures of the first injection string section 43. When the outflow control valve 1007 is in an open position, fluid may be pumped through the first injection string section 43 and into the first lateral wellbore section 1009 through the one or more apertures of the first injection string section 43.
At step 1109, the system 1000 may increase a hydrostatic pressure within the first lateral wellbore section 1009. As described herein, when the outflow control valve 1007 is in an open position, fluid may be pumped through the first injection string section 43 and into the first lateral wellbore section 1009 through the one or more apertures of the first injection string section 43. The fluid that is pumped into the first lateral wellbore section 1009 may create a hydrostatic pressure within the first lateral wellbore section 1009 that is greater than a formation pressure of the adjacent terrestrial formation 19.
At step 1111, the system 1000 may force production fluid that is adjacent the first lateral wellbore section 1009 away from the first lateral wellbore section 1009. When the outflow control valve 1007 is in an open position, fluid may be pumped through the first injection string section 43 and into the first lateral wellbore section 1009 through the one or more apertures of the first injection string section 43. The outflow control valve 1007 may modulate or control the volumetric flow rate of fluid injecting into the first lateral wellbore section 1009 and form a hydrostatic pressure within the first lateral wellbore section 1009 that is greater than a formation pressure of the adjacent terrestrial formation 19. The pressure differential between the first lateral wellbore section 1009 and the adjacent terrestrial formation 19 may force production fluid away from the first lateral wellbore section 1009.
At step 1113, the system 1000 may draw production fluid that is adjacent the lateral wellbore 21 into the second lateral wellbore section 1011. When the outflow control valve 1007 is in an open position, fluid may be pumped through the first injection string section 43 and into the first lateral wellbore section 1009 through the one or more apertures of the first injection string section 43 creating a hydrostatic pressure within the first lateral wellbore section 1009 that is greater than a formation pressure of the adjacent terrestrial formation 19. The pressure differential between the first lateral wellbore section 1009 and the adjacent terrestrial formation 19 may force production fluid away from the first lateral wellbore section 1009 and into the underbalanced circulation stream in the second lateral wellbore section 1011. Subsequently, production fluid that is received by the underbalanced circulation stream in the second lateral wellbore section 1011 may be drawn off by an artificial lift system 35 and into the return string 31.
In certain embodiments, the outflow control valve 1007 may include one or more apertures 1008 through the first injection string section 43 that are located in the second lateral wellbore section 1011. The apertures 1008 may be configured to inject fluid from the first injection string section 43 directly into the second lateral wellbore section 1011. The outflow control valve 1007 may modulate or control both the volumetric flow rate of fluid injecting from the first injection string section 43 into the first lateral wellbore section 1009 and the volumetric flow rate of fluid injecting from the first injection string section 43 into the second lateral wellbore section 1011 through the one or more apertures 1008 forming a hydrostatic pressure within the first lateral wellbore section 1009 that is greater than a formation pressure of the adjacent terrestrial formation 19. The outflow control valve 1007 may also modulate or control the volumetric flow rate of fluid injecting into the second lateral wellbore section 1011 and form a hydrostatic pressure within the second lateral wellbore section 1011 that is less than a formation pressure of the adjacent terrestrial formation 19. The outflow control valve 1007 may also control the volumetric flow rate of fluid injecting into the second lateral wellbore section 1011 to achieve a underbalanced circulation stream in the second lateral wellbore section 1011. Thus, production fluid in the terrestrial formation 19 may be forced away from the first lateral wellbore section 1009 and drawn into the second lateral wellbore section 1011 due to the lower hydrostatic pressure and underbalanced circulation stream. Subsequently, production fluid that is received by the underbalanced circulation stream in the second lateral wellbore section 1011 may be drawn off by an artificial lift system 35 and into the return string 31.
At step 1115, the system 1000 may receive production fluid from the wellbore 15 through the return string 1031. Step 1115 is at least similar to step 207 of method 200 illustrated in FIG. 2. At step 1117, the system 1000 may communicate production fluid from the wellbore 15 to a surface 17 of a terrestrial formation 19. Step 1117 is at least similar to step 207 of method 200 illustrated in FIG. 2.
In certain embodiments, a method for recovering fluid from a well using a production fluid recovery system is provided. The method may include extending a return string from a surface of a terrestrial formation and through at least a portion of a wellbore. The return string may be for receiving fluid from a lateral section of the wellbore. The method may also include extending an injection string from the surface of the terrestrial formation and through at least a portion of the lateral section of the wellbore to communicate fluid to the lateral section of the wellbore. The injection string may include a first injection string section located at a distal end of the injection string and for communicating fluid through at least the portion of the lateral section of the wellbore. The first injection string section may include a first cross-sectional area. The injection string may also include a second injection string section located at a proximal end of the injection string and for communicating fluid from the surface of the terrestrial formation to the first injection string section. The second injection string section may include a second cross-sectional area that is less than the first cross-sectional area. The method may further include receiving fluid through the return string from the wellbore. In addition, the method may include reducing a hydrostatic pressure of fluid in the lateral section of the wellbore when the return string receives the fluid from the wellbore.
In certain embodiments, a system for recovering production fluid from a well is provided. The system may include a first injection string section for communicating fluid to a lateral section of a wellbore. The first injection string section may include a first cross-sectional area and an anchor assembly for securing the first injection string section to a fixed position within the wellbore. The system may also include a second injection string section for communicating fluid into the wellbore from a surface of a terrestrial formation. The second injection string section may include a second cross-sectional area that is less than the first cross-sectional area. The system may further include a latch assembly for removably coupling a proximal end of the first injection string section to a distal end of the second injection string section when the anchor assembly secures the first injection string section to the fixed position within the wellbore. In addition, the system may include an artificial lift for drawing fluid from the lateral section of the wellbore.
In certain embodiments, a method for recovering fluid from a well using a production fluid recovery system is provided. The method may include extending a first injection string section through a wellbore and at least partial into a lateral section of the wellbore. The first injection string section may include a first cross-sectional area. The method may also include anchoring the first injection string section to a fixed positioned within the wellbore. The method may further include extending a second injection string section from a surface of a terrestrial formation into the wellbore. The second injection string section may include a second cross-sectional area that is less than the first cross-sectional area. In addition, the method may include coupling a proximal end of the first injection string section to a distal end of the second injection string section when the first injection string section is anchored to the fixed position within the wellbore. The method may include drawing fluid from the lateral section of the wellbore. The method may also include reducing a hydrostatic pressure of fluid in the lateral section of the wellbore when the fluid is drawn from the lateral section of the wellbore. In certain embodiments, the method may also include delivering fluid to the lateral section of the wellbore through the first injection string section and the second injection string section when the proximal end of the first injection string section is coupled to the distal end of the second injection string section.
In certain embodiments, a method for recovering fluid from a well using a production fluid recovery system is provided. The method may include extending a return string from a surface of a terrestrial formation and through at least a portion of the wellbore. The return string may be for receiving fluid from a lateral section of the wellbore. The method may also include fluidly dividing an annulus of the lateral section of the wellbore into a first lateral section and a second lateral section. The method may further include extending an injection string from the surface of the terrestrial formation, through the second lateral section, and into the first lateral section to communicate fluid to the first lateral section. The injection string may include a first injection string section located at a distal end of the injection string and for communicating fluid through the second lateral section and through at least a portion of the first lateral section. The first injection string section may include a first cross-sectional area. The injection string may also include a second injection string section located at a proximal end of the injection string and for communicating fluid from the surface of the terrestrial formation to the first injection string section. The second injection string section may include a second cross-sectional area that is less than the first cross-sectional area. In addition, the method may include communicating fluid through the injection string into the first lateral section. The method may include increasing a hydrostatic pressure of fluid in the first lateral section when the first lateral section receives fluid from the injection string. In certain embodiments, the method may include forcing production fluid that is adjacent the lateral section of the wellbore to move away from the first lateral section and into the second lateral section. In certain embodiments, the method may include controlling a volumetric flow rate of fluid communicating from the first injection string section into the first lateral section. In certain embodiments, the method may include bleeding fluid from the first injection string section into second lateral section to control a volume of fluid communicating from the first injection string section into the first lateral section and to generate an underbalanced circulation stream in the second lateral section.
In certain embodiments, a system for removing an obstruction in a wellbore is provided. The system may include an injection string for communicating fluid from a surface of a terrestrial formation to a lateral section of the wellbore. The injection string may include a first injection string section located at a distal end of the injection string and for communicating fluid to the lateral section of the wellbore. The first injection string section may include a first cross-sectional area. The injection string may also include a second injection string section located at a proximal end of the injection string and for communicating fluid from the surface of the terrestrial formation to the first injection string section. The second injection string section may include a second cross-sectional area that is less than the first cross-sectional area. The system may also include a surface system for injecting treatment fluid into the injection string. The system may further include a control system for detecting an obstruction in the wellbore and for directing the surface system to inject the treatment fluid into the injection string to remove at least some of the obstruction from the wellbore and achieve an underbalance low pressure circulation stream in the lateral section of the wellbore.
FIG. 12 illustrates a non-limiting, example computer system 1200 configured to implement systems and methods for operating a production fluid recovery system and a surface system according to certain embodiments of this disclosure. FIG. 12 illustrates a computer system 1200 that is configured to execute any and all of the embodiments described herein. In certain embodiments, the computer system 1200 describes at least some of the components of the production fluid recovery system 800 including the control system 850 of the surface system 801 illustrated in FIG. 8 and described with respect to FIGS. 8 and 9. In certain embodiments, the computer system 1200 describes at least some of the components of the production fluid recovery system 100 and 1000 illustrated in FIGS. 1, 4-7, and 10, and described with respect to FIGS. 1-7, 10, and 11. In different embodiments, the computer system 1200 may be any of various types of devices, including, but not limited to, a computer embedded in a vehicle, a computer embedded in an appliance, a personal computer system, a desktop computer, a handset (e.g., a laptop computer, a notebook computer, a tablet, a slate, a netbook computer, a camera, a handheld video game device, a handheld computer, a video recording device, a consumer device, a portable storage device, or the like), a mainframe computer system, a workstation, network computer, a set top box, a video game console, a mobile device (e.g., electronic controller of a handset), an application server, a storage device, a television, a peripheral device such as a switch, modem, router, or in general any type of computing or electronic device.
Various embodiments of a system and method for operating a production fluid recovery system and a surface system, as described herein, may be executed on one or more computer systems 1200, which may interact with various other devices. In the illustrated embodiment, the computer system 1200 includes one or more processors 1205 coupled to a system memory 1210 via an input/output (I/O) interface 1215. The computer system 1200 further includes a network interface 1220 coupled to I/O interface 1215, and one or more input/output devices 1225, such as cursor control device, keyboard, and display(s). In some cases, it is contemplated that embodiments may be implemented using a single instance of computer system 1200, while in other embodiments multiple such systems, or multiple nodes making up computer system 1200, may be configured to host different portions or instances of embodiments. For example, in one embodiment some elements may be implemented via one or more nodes of computer system 1200 that are distinct from those nodes implementing other elements.
In various embodiments, computer system 1200 may be a uniprocessor system including one processor 1205 a, or a multiprocessor system including several processors 1205 a-1205 n (e.g., two, four, eight, or another suitable number). The processors 1205 may be any suitable processor capable of executing instructions. For example, in various embodiments the processors 1205 may be general-purpose or embedded processors implementing any of a variety of instruction set architectures (ISAs), such as the x86, PowerPC, SPARC, or MIPS ISAs, or any other suitable ISA. In multiprocessor systems, each of processors 1205 may commonly, but not necessarily, implement the same ISA.
The system memory 1210 may be configured to store the program instructions 1230 and/or existing state information and ownership transition condition data in the data storage 1235 accessible by the processor 1205. In various embodiments, the system memory 1210 may be implemented using any suitable memory technology, such as static random access memory (SRAM), synchronous dynamic RAM (SDRAM), nonvolatile/Flash-type memory, or any other type of memory. In the illustrated embodiment, the program instructions 1230 may be configured to implement a system for operating a production fluid recovery system and a surface system incorporating any of the functionality, as described herein. In some embodiments, program instructions and/or data may be received, sent, or stored upon different types of computer-accessible media or on similar media separate from the system memory 1210 or the computer system 1200. The computer system 1200 is described as implementing at least some of the functionality of functional blocks of previous Figures.
In one embodiment, the I/O interface 1215 may be configured to coordinate I/O traffic between the processor 1205, the system memory 1210, and any peripheral devices in the device, including the network interface 1220 or other peripheral interfaces, such as the input/output devices 1225. In some embodiments, the I/O interface 1215 may perform any necessary protocol, timing or other data transformations to convert data signals from one component (e.g., the system memory 1210) into a format suitable for use by another component (e.g., the processor 1205). In some embodiments, the I/O interface 1215 may include support for devices attached through various types of peripheral buses, such as a variant of the Peripheral Component Interconnect (PCI) bus standard or the Universal Serial Bus (USB) standard, for example. In some embodiments, the function of the I/O interface 1215 may be split into two or more separate components, such as a north bridge and a south bridge, for example. Also, in some embodiments some or all of the functionality of the I/O interface 1215, such as an interface to the system memory 1210, may be incorporated directly into the processor 1205.
The network interface 1220 may be configured to allow data to be exchanged between the computer system 1200 and other devices (e.g., one or more sensors, one or more actuators) attached to the network or between nodes of the computer system 1200. The network may in various embodiments include one or more networks including but not limited to Local Area Networks (LANs) (e.g., an Ethernet or corporate network), Wide Area Networks (WANs) (e.g., the Internet), wireless data networks, some other electronic data network, a combination thereof, or the like. In various embodiments, the network interface 1220 may support communication via wired or wireless general data networks, such as any suitable type of Ethernet network, for example; via telecommunications/telephony networks such as analog voice networks or digital fiber communications networks; via storage area networks such as Fiber Channel SANs, or via any other suitable type of network and/or protocol.
The input/output devices 1225 may, in some embodiments, include one or more display terminals, keyboards, keypads, touchpads, scanning devices, voice, or optical recognition devices, or any other devices suitable for entering or accessing data by one or more the computer systems 1200. Further, various other sensors may be included in the I/O devices 1225, such as imaging sensors, barometers, altimeters, LIDAR, or any suitable environmental sensor. Multiple input/output devices 1225 may be present in the computer system 1200 or may be distributed on various nodes of the computer system 1200. In some embodiments, similar input/output devices may be separate from the computer system 1200 and may interact with one or more nodes of the computer system 1200 through a wired or wireless connection, such as over the network interface 1220.
As shown in FIG. 12, the memory 1210 may include program instructions 1230, which may be processor-executable to implement any element or action, as described herein. In one embodiment, the program instructions may implement at least a portion of methods described herein. In other embodiments, different elements and data may be included. Note that the data storage 1235 may include any data or information, as described herein.
Those skilled in the art will appreciate that the computer system 1200 is merely illustrative and is not intended to limit the scope of embodiments. In particular, the computer system and devices may include any combination of hardware or software that can perform the indicated functions, including computers, network devices, Internet appliances, PDAs, wireless phones, pagers, GPUs, specialized computer systems, information handling apparatuses, or the like. The computer system 1200 may also be connected to other devices that are not illustrated, or instead may operate as a stand-alone system. In addition, the functionality provided by the illustrated components may in some embodiments be combined in fewer components or distributed in additional components. Similarly, in some embodiments, the functionality of some of the illustrated components may not be provided and/or other additional functionality may be available.
Those skilled in the art will also appreciate that, while various items are illustrated as being stored in memory or on storage while being used, these items or portions of them may be transferred between memory and other storage devices for purposes of memory management and data integrity. Alternatively, in other embodiments some or all of the software components may execute in memory on another device and communicate with the illustrated computer system via inter-computer communication. Some or all of the system components or data structures may also be stored (e.g., as instructions, structured data) on a computer-accessible medium or a portable article to be read by an appropriate drive, various examples of which are described here. In some embodiments, instructions stored on a computer-accessible medium separate from the computer system 1200 may be transmitted to the computer system 1200 through transmission media or signals such as electrical, electromagnetic, or digital signals, conveyed via a communication medium such as a network and/or a wireless link. Various embodiments may further include receiving, sending, or storing instructions and/or data implemented in accordance with the foregoing description upon a computer-accessible medium. Generally speaking, a computer-accessible medium may include a non-transitory, computer-readable storage medium or memory medium such as magnetic or optical media, e.g., disk or DVD/CD-ROM, volatile or non-volatile media such as RAM (e.g., SDRAM, DDR, RDRAM, SRAM, or the like), ROM, or the like. In some embodiments, a computer-accessible medium may include transmission media or signals such as electrical, electromagnetic, or digital signals, conveyed via a communication medium such as network and/or a wireless link.
Thus, the disclosure provides, among other things, a system for operating a production fluid recovery system and a surface system, including a computing system. None of the description in this application should be read as implying that any particular element, step, or function is an essential element that must be included in the claim scope. The scope of patented subject matter is defined only by the claims. Moreover, none of the claims is intended to invoke 35 U.S.C. § 112(f) unless the exact words “means for” are followed by a participle.

Claims

What is claimed is:

1. A system for recovering production fluid from a well, the system comprising:

a return string for receiving fluid from a lateral section of a wellbore, wherein the return string is configured to extend from a surface of a terrestrial formation through at least a portion of the wellbore; and

an injection string for communicating fluid from the surface of the terrestrial formation to the lateral section of the wellbore, wherein the injection string comprises:

a first injection string section located at a distal end of the injection string and for communicating fluid through at least a portion of the lateral section of the wellbore, wherein the first injection string section includes a first cross-sectional area, and

a second injection string section located at a proximal end of the injection string and for communicating fluid from the surface of the terrestrial formation to the first injection string section, wherein the second injection string section includes a second cross-sectional area that is less than the first cross-sectional area.

2. The system of claim 1, wherein when the return string receives fluid from the wellbore, a hydrostatic pressure decreases within the lateral section of the wellbore.

3. The system of claim 1, wherein when the return string receives fluid from the wellbore, an underbalanced circulation stream forms within the lateral section of the wellbore.

4. The system of claim 3, wherein a velocity of the underbalanced circulation stream is at least about 50 feet per minute (fpm).

5. The system of claim 1, wherein when the injection string communicates fluid to the lateral section of the wellbore, a pressure within the injection string is at least about 400 pounds per square inch (psi) less than a pressure within a fluid reservoir that is adjacent the lateral section of the wellbore.

6. The system of claim 1, further comprising an artificial lift positioned in fluid communication with the return string and for drawing fluid from the wellbore into the return string.

7. The system of claim 1, wherein the first injection string section is configured to removably attached to the second injection string section.

8. A method for removing an obstruction in a wellbore using a production fluid recovery system, the method comprising:

extending an injection string from a surface of a terrestrial formation and through at least a portion of the lateral section of the wellbore to communicate fluid to the lateral section of the wellbore, wherein the injection string comprises:

a first injection string section located at a distal end of the injection string and for communicating fluid through at least the portion of the lateral section of the wellbore, wherein the first injection string section includes a first cross-sectional area, and

a second injection string section located at a proximal end of the injection string and for communicating fluid from the surface of the terrestrial formation to the first injection string section, wherein the second injection string section includes a second cross-sectional area that is less than the first cross-sectional area;

communicating fluid through injection string;

detecting an obstruction within the wellbore; and

injecting a treatment fluid into the injection string in response to detecting the obstruction in the wellbore, wherein the treatment fluid injected into the injection string is to remove at least some of the obstruction from the wellbore and achieve an underbalance low pressure circulation stream in the lateral section of the wellbore.

9. The method of claim 8, further comprising extending a return string from the surface of the terrestrial formation and through at least a portion of the wellbore, wherein the return string is for receiving fluid from the lateral section of the wellbore.

10. The method of claim 9, further comprising:

positioning an artificial lift into fluid communication with the return string to draw fluid into the return string; and

performing at least one of injecting the treatment fluid into the injection string or directing the artificial lift to adjust a flow rate of fluid that is received by the return string to remove at least some of the obstruction from the wellbore and achieve an underbalance low pressure circulation stream in the lateral section of the wellbore.

11. The method of claim 8, wherein detecting the obstruction within the wellbore comprises detecting at least one of a location of the obstruction or a type of the obstruction.

12. The method of claim 11, wherein detecting at least one of a location of the obstruction or the type of the obstruction is based on at least one of a location of one or more sensors within the wellbore or a pressure, a fluid velocity, a volumetric flow rate, or a temperature sensed by one or more sensors within the wellbore.

13. The method of claim 8, wherein the treatment fluid comprises at least one of a hot treatment fluid, a chemical treatment fluid, or an acidic chemical treatment fluid,

14. A system for recovering production fluid from a well, the system comprising:

a return string for receiving fluid from a lateral section of a wellbore, wherein the return string is configured to extend from a surface of a terrestrial formation through at least a portion of the wellbore;

a second injection string section located at a proximal end of the injection string and for communicating fluid from the surface of the terrestrial formation to the first injection string section, wherein the second injection string section includes a second cross-sectional area that is less than the first cross-sectional area; and

a packer positioned within the lateral section of the wellbore to fluidly divide the lateral section of the wellbore into a first lateral section and a second lateral section, wherein the packer includes an aperture that receives the first injection string section from the second lateral section and permits the first injection string section to extend into the first lateral section.

15. The system of claim 14, wherein when fluid is received by the first lateral section from the first injection string section, a hydrostatic pressure within the first lateral section increases and forces production fluid adjacent to the lateral section of the wellbore to move away from the first lateral section and into the second lateral section.

16. The system of claim 15, further comprising a flow valve positioned along the first injection string section, wherein the flow valve controls a volume of fluid communicated from the first injection string section to the first lateral section.

17. The system of claim 15, further comprising a flow valve positioned along the first injection string section and within the second lateral section, wherein the flow valve controls a volume of fluid communicated from the first injection string section to the first lateral section, and wherein the flow valve controls a volume of fluid communicated from the first injection string section to the second lateral section creating an underbalanced circulation stream in the second lateral section.

18. The system of claim 14, wherein the lateral section of the wellbore comprises a liner, and wherein the first cross-section area of the first injection string section reduces a cross-sectional area of an annulus between the liner and the first injection string section.

19. The system of claim 14, wherein the second cross-sectional area of the second injection string section creates a restriction in the injection string to counteract hydrostatic pressure from a weight of fluid inside the lateral section of the wellbore.

20. The system of claim 14, wherein a pressure difference between the first injection string section and the second injection string section is at least about 50%.