US20100200230A1 - Method and Apparatus for Multi-Zone Stimulation - Google Patents

Method and Apparatus for Multi-Zone Stimulation Download PDF

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Publication number
US20100200230A1
US20100200230A1 US12/369,863 US36986309A US2010200230A1 US 20100200230 A1 US20100200230 A1 US 20100200230A1 US 36986309 A US36986309 A US 36986309A US 2010200230 A1 US2010200230 A1 US 2010200230A1
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United States
Prior art keywords
tool
zone
tubing string
subterranean formation
method
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Abandoned
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US12/369,863
Inventor
Loyd East, Jr.
Dan Morrison
Milorad Stanojcic
Perry Courville
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Halliburton Energy Services Inc
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Halliburton Energy Services Inc
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Priority to US12/369,863 priority Critical patent/US20100200230A1/en
Assigned to HALLIBURTON ENERGY SERVICES, INC. reassignment HALLIBURTON ENERGY SERVICES, INC. ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: MORRISON, DAN, COURVILLE, PERRY, EAST, LOYD, JR., STANOJCIC, MILORAD
Publication of US20100200230A1 publication Critical patent/US20100200230A1/en
Application status is Abandoned legal-status Critical

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    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B23/00Apparatus for displacing, setting, locking, releasing, or removing tools, packers or the like in the boreholes or wells
    • E21B23/08Introducing or running tools by fluid pressure, e.g. through-the-flow-line tool systems
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/11Perforators; Permeators
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25Methods for stimulating production
    • E21B43/26Methods for stimulating production by forming crevices or fractures
    • E21B43/267Methods for stimulating production by forming crevices or fractures reinforcing fractures by propping

Abstract

Methods of treating a well bore in a single trip are provided. A tubing string may be inserted into a subterranean formation having a well bore, where the tubing string has a locking device on an end. A workover tool may be positioned in a first zone of the subterranean formation, where the workover tool engages the locking device. One or more perforations may be created or enhanced in a first zone of a subterranean formation using the workover tool, and the tubing string may be positioned in a second zone of the subterranean formation. A fracturing fluid may be introduced into the first zone of the subterranean formation at a rate and pressure sufficient to create or enhance one or more fractures in the subterranean formation. The first zone of the subterranean formation may be isolated from the second zone of the subterranean formation and one or more perforations in the second zone of the subterranean formation may be created or enhanced using the workover tool.

Description

    BACKGROUND OF THE INVENTION
  • The present invention relates to stimulation of subterranean formations, and more particularly, to a novel apparatus and methods of multi-zone stimulation of subterranean formations, in particular, at least in some embodiments, in high temperature, high pressure wells.
  • Treatment fluids may be used in a variety of subterranean treatments, including, but not limited to, stimulation treatments and sand control treatments. As used herein, the term “treatment,” or “treating,” refers to any subterranean operation that uses a fluid in conjunction with a desired function and/or for a desired purpose. The term “treatment,” or “treating,” does not imply any particular action by the fluid or any particular component thereof.
  • One common production stimulation operation that employs a treatment fluid is hydraulic fracturing. Hydraulic fracturing operations generally involve pumping a treatment fluid (e.g., a fracturing fluid) into a well bore that penetrates a subterranean formation at a sufficient hydraulic pressure to create or enhance one or more cracks, or “fractures,” in the subterranean formation. “Enhancing” one or more fractures in a subterranean formation, as that term is used herein, is defined to include the extension or enlargement of one or more natural or created fractures in the subterranean formation. The treatment fluid may comprise particulates, often referred to as “proppant particulates,” that are deposited in the fractures. The proppant particulates, inter alia, may prevent the fractures from fully closing upon the release of hydraulic pressure, forming conductive channels through which fluids may flow to the well bore. Once at least one fracture is created and the proppant particulates are substantially in place, the treatment fluid may be “broken” (i.e., the viscosity of the fluid reduced), and the treatment fluid may be recovered from the formation.
  • Maintaining sufficient viscosity in these treatment fluids is important for a number of reasons. Maintaining sufficient viscosity is important in fracturing and sand control treatments for particulate transport and/or to create or enhance fracture width. Also, maintaining sufficient viscosity may be important to control and/or reduce fluid-loss into the formation. Moreover, a treatment fluid of a sufficient viscosity may be used to divert the flow of fluids present within a subterranean formation (e.g., formation fluids, other treatment fluids) to other portions of the formation, for example, by “plugging” an open space within the formation. At the same time, while maintaining sufficient viscosity of the treatment fluid often is desirable, it also may be desirable to maintain the viscosity of the treatment fluid in such a way that the viscosity may be reduced at a particular time, inter alia, for subsequent recovery of the fluid from the formation.
  • To provide the desired viscosity, polymeric gelling agents may be added to the treatment fluids. Examples of commonly used polymeric gelling agents include, but are not limited to, guar gums and derivatives thereof, cellulose derivatives, biopolymers, polysaccharides, synthetic polymers, and the like. To further increase the viscosity of a treatment fluid, often the molecules of the gelling agent are “crosslinked” with the use of a crosslinking agent. Conventional crosslinking agents usually comprise a metal ion that interacts with at least two polymer molecules to form a “crosslink” between them.
  • At some point in time, e.g., after a viscosified treatment fluid has performed its desired function, the viscosity of the viscosified treatment fluid should be reduced. This is often referred to as “breaking the gel” or “breaking the fluid.” This can occur by, inter alia, reversing the crosslink between crosslinked polymer molecules, breaking down the molecules of the polymeric gelling agent, or breaking the crosslinks between polymer molecules. The use of the term “break” herein incorporates at least all of these mechanisms. Certain breakers that are capable of breaking treatment fluids comprising crosslinked gelling agents are known in art. For example, breakers comprising sodium bromate, sodium chlorite, and other oxidizing agents have been used to reduce the viscosity of treatment fluids comprising crosslinked polymers.
  • Certain subterranean formations, however, have properties that may make stimulation operations difficult, time consuming, and/or expensive. For example, high-temperature high-pressure (“HTHP”) wells may present operating difficulties. For example, the conditions in the formation may reach temperatures as high as 600° F. and experience high pressures of approximately 5,000 psi. HTHP wells may also be deep wells with bottom hole depths of greater than 10,000 feet to 50,000 feet. For these deep wells, a single trip with jointed tubing may take a considerable amount of time, making any workover operation with several trips in and out of the well bore expensive and inefficient. These wells may require specialized tools to economically complete and workover in an efficient manner.
  • An example of a treatment in a HTHP well may include perforating the casing, which may require removing the tubing during the perforation followed by replacing the tubing to treat the perforated zone. This is particularly inefficient when multiple intervals in a well are to be perforated and stimulated separately. As another example, may be the replacement of worn or eroded tools used to perform isolation of each interval to be treated such as packers or bridge plugs; or in the case of hydra-jet perforating the hydra-jetting tool may become worn or plugged requiring removal of the tubing. In the case of hydra-jet perforating operation, it may be necessary to remove the hydra-jetting device from the tubing to allow high-rate pumping down the tubing during a fracturing treatment. Yet another example that may involve the removal of the tubing between stimulation treatments may be the remediation of early screen-out of a fracturing treatment. In this embodiment, a bottom-hole assembly used to fracture the interval may need to be replaced with an assembly to facilitate well bore cleanout in order to enable the continuation of a multiple interval completion treatment.
  • If the tubing must be removed during a treatment, it may be necessary to deploy a device to the Bottom hole Assembly that would act to shut-off fluid flow up the tubing in order to enable safe removal of the tubing under ‘live well’ conditions. Such an operation may involve yet another trip into the well with a profile plug or similar tool run on slickline before safely removing the tubing.
  • SUMMARY OF THE INVENTION
  • The present invention relates to stimulation of subterranean formations, and more particularly, to a novel apparatus and methods of multi-zone stimulation of subterranean formations, in particular, at least in some embodiments, in high temperature, high pressure wells.
  • An embodiment of the present invention provides a method of treating a well bore in a single trip, the method comprising inserting a tubing string into a subterranean formation comprising a well bore, wherein the tubing string has a locking device disposed on an end; positioning a workover tool in a first zone of the subterranean formation, wherein the workover tool engages the locking device; creating or enhancing one or more perforations in a first zone of a subterranean formation using the workover tool; positioning the tubing string in a second zone of the subterranean formation; introducing a fracturing fluid into the first zone of the subterranean formation at a rate and pressure sufficient to create or enhance one or more fractures in the subterranean formation; isolating the first zone of the subterranean formation from the second zone of the subterranean formation; and creating or enhancing one or more perforations in the second zone of the subterranean formation using the workover tool.
  • Another embodiment of the present invention provides a method of treating a well bore in a single trip, the method comprising using a hydraulic workover unit to introduce a tubing string into a subterranean formation comprising a well bore, wherein the tubing string has a locking device disposed on an end; introducing a logging tool into a well bore to position the end of the tubing string; engaging a hydrajetting tool with the locking device in a first zone of the subterranean formation; creating or enhancing one or more perforations in the first zone of the subterranean formation using the hydrajetting tool; positioning a hydrajetting tool in a second zone of the subterranean formation; pumping a fluid at a rate and pressure sufficient to create or enhance one or more fractures in the subterranean formation; and isolating the first zone from the second zone.
  • Still another embodiment of the present invention provides a downhole tool system comprising a profile nipple disposed on a tubing string, where the profile nipple comprises a locking receptacle; and a tool assembly, where the tool assembly has a locking lug, wherein the locking lug engages the locking lug receptacle, wherein the tool assembly may be passed through the tubing string to engage the profile nipple.
  • The features and advantages of the present invention will be apparent to those skilled in the art. While numerous changes may be made by those skilled in the art, such changes are within the spirit of the invention.
  • BRIEF DESCRIPTION OF THE DRAWINGS
  • These drawings illustrate certain aspects of some of the embodiments of the present invention, and should not be used to limit or define the invention.
  • FIG. 1 illustrates a cross sectional view of a well bore disposed in a subterranean formation in which an embodiment of the disclosed invention may be used.
  • FIG. 2 illustrates a cross sectional view of an embodiment of a locking device that may be disposed on a tubing string in the present invention.
  • FIG. 3 illustrates a cross sectional view of an embodiment of tool that may be useful with the present invention.
  • FIG. 4 illustrates a cross sectional view of an embodiment of another tool that may be useful with the present invention.
  • FIG. 5 illustrates a cross sectional view of an embodiment of still another tool that may be useful with the present invention.
  • FIG. 6A illustrates a cross sectional view of a well bore disposed in a subterranean formation in which an embodiment of the disclosed invention may be used.
  • FIG. 6B illustrates another cross sectional view of a well bore disposed in a subterranean formation in which an embodiment of the disclosed invention may be used.
  • FIG. 6C illustrates yet another cross sectional view of a well bore disposed in a subterranean formation in which an embodiment of the disclosed invention may be used.
  • FIG. 6D illustrates still another cross sectional view of a well bore disposed in a subterranean formation in which an embodiment of the disclosed invention may be used.
  • FIG. 6E illustrates another cross sectional view of a well bore disposed in a subterranean formation in which an embodiment of the disclosed invention may be used.
  • FIG. 6F illustrates yet another cross sectional view of a well bore disposed in a subterranean formation in which an embodiment of the disclosed invention may be used.
  • FIG. 6G illustrates still another cross sectional view of a well bore disposed in a subterranean formation in which an embodiment of the disclosed invention may be used.
  • DETAILED DESCRIPTION
  • The present invention relates to stimulation of subterranean formations, and more particularly, to a novel apparatus and methods of multi-zone stimulation of subterranean formations, in particular, at least in some embodiments, in high temperature, high pressure wells.
  • As used herein, directional terms including “top”, “above”, “upper”, “bottom”, “below”, and “underneath” refer to directions within the well bore such that the top of the well is the upper most point and the bottom of the well is the furthest point from the surface through the well bore. Some wells may not be entirely vertical and may have horizontal or slanted portions. In these wells, the bottom of the well still refers to the point in the well bore furthest from the top, even though it may not be the deepest point of the well on a strictly vertical basis.
  • Also, as used herein, the term “treatment fluid” refers generally to any fluid that may be used in a subterranean application in conjunction with a desired function and/or for a desired purpose. The term “treatment fluid” does not imply any particular action by the fluid or any component thereof. Similarly, the term “treatment” does not refer to any type of treatment in particular unless noted otherwise.
  • While there are many advantages of the apparatus and methods disclosed herein, only some will be discussed or alluded to herein. One advantage of the present invention is the incorporation of several tools and methods into a single operation to allow the efficient and cost effective treatment in a high-temperature high-pressure (“HTHP”) well. In an embodiment, the use of a hydraulic workover unit may allow the workover of the HTHP well to be completed under conditions of high pressure in a safe and efficient manner. Utilizing a hydraulic workover unit may allow fluid to be transferred in and out of the well bore through both a tubing string and the annular space between the tubing and casing. In addition, the present disclosure includes methods of using the apparatus to perforate, fracture, and treat multiple formation intervals in a single trip with jointed tubing into the well bore. This may be advantageous for HTHP wells. For deep wells, a single trip with jointed tubing may take a considerable amount of time, making any workover operation with several trips in and out of the well bore expensive and inefficient. The efficiencies gained by the unique deployment of these tools may allow for an efficient replacement of tools in the event of unplanned events such as the premature failure of the tools or remediation of early screen-outs during multiple interval stimulation treatments
  • In an embodiment, the apparatus of the present disclosure may comprise a downhole tool system disposed on tubing string with an interchangeable set of tools for performing treatment operations.
  • In one embodiment, the present invention provides a downhole tool system comprising: a profile nipple disposed on a tubing string, wherein the profile nipple comprises a locking receptacle; and a tool assembly, wherein the tool assembly has a locking lug, wherein the locking lug engages the locking lug receptacle, wherein the tool assembly may be passed through the tubing string to engage the profile nipple. In some embodiments, the tool assembly comprises at least one tool selected from the group consisting of: a perforating gun, and a washing tool. In some embodiments, the tool comprises a hydrajetting tool. In some embodiments, the hydrajetting tool comprises dual check valves. In some embodiments, the tool assembly may be engaged and retrieved by a wireline, a slickline, or coiled tubing. These embodiments are discussed below.
  • In an embodiment, a locking device may be disposed on the end of a tubing string within a subterranean formation. A variety of tools utilizing locking lugs for engaging the locking device may be used to treat the formation by passing the tools through the interior of the tubing string until they lockingly engage the locking device on the end of the tubing string. In an embodiment, a hydraulic workover unit may be utilized to allow the treatment operations to proceed while the well is under pressure. The downhole tool system and the various tools that may be used are described in more detail below.
  • In an embodiment, the apparatus of the present disclosure may be used in a well bore disposed in a subterranean formation. In an embodiment shown in FIG. 1, a well bore 10 may be created so as to extend into a subterranean formation 22. A casing 12 may be disposed within the well bore and cement 14 may be introduced between the casing 12 and the well bore 10 walls in order to hold the casing 12 in place and prevent the migration of fluids between the casing 12 and the well bore 10 walls. A tubing string 16 may be disposed within the casing 12. In an embodiment, the tubing string 16 may be jointed tubing, coiled tubing, or any other type of tubing suitable for use in a subterranean well environment. Suitable types of tubing and an appropriate choice of tubing diameter and thickness may be known to one skilled in the art, considering factors such as well depth, pressure, temperature, chemical environment, and suitability for its intended use. In an embodiment, a hydraulic workover unit 20 may be disposed at or near the top of the tubing string 16, the casing 12, or both. The hydraulic workover unit 20 may allow for tubing and other items to be introduced into the well bore 10 while a pressure exists and is maintained within the well bore 10 and tubing string 16. The existence of a pressure within the well bore may be referred to as a live well condition.
  • In an embodiment shown in FIG. 2, the end of the tubing string 16 may contain a locking device that may allow a connection with a tool. In an embodiment, the locking device may be a profile nipple 18. The profile nipple 18 may be designed to allow a variety of tools to be connected to the tubing string such that they may lock into a locking receptacle 24 on the profile nipple 10. In this embodiment, the variety of tools may be passed through the tubing string until locking lugs on the tools lockingly engage the locking receptacles 24 on the profile nipple. The tool may then be utilized on the end of the tubing string to perform a treatment operation. While the terms locking receptacle and locking lugs are used herein, the tools may engage the tubing string using any type of locking device and should not be limited to locking devices with lugs. As used herein, the term locking lugs refers to any device capable of providing a temporary fixed relationship between a tool and tubing. The locking lugs can be released from their temporary fixed relationship through manipulation with a retrieving device on slickline, wireline, coiled tubing, or through the exertion of a physical force on the locking lugs such as pressure in the tubing or a set down force on the tool itself.
  • In an embodiment, a tool capable of engaging the locking lug receptacles on the tubing string may be passed through the tubing string. In this embodiment, the tool may be lowered to the profile nipple in any manner capable of placing a tool in a subterranean formation. For example, the tool may be lowered using a wireline, a slickline, or coiled tubing. In another embodiment, the tool may be placed inside the tubing string and a pressurized fluid introduced above the tool. The pressurized fluid may then cause the tool to move through the tubing string so as to lock into position upon reaching the profile nipple. In an embodiment, any of the same methods may be used to remove the tool from the profile nipple once the treatment operation has been completed. For example, a slickline, wireline, or coiled tubing may be used to remove the tool from the profile nipple. In another embodiment, a pressurized fluid may be introduced into the annular space between the tubing string and the casing so as to cause the tool to move back up the tubing string towards the hydraulic workover unit. In still another embodiment the locking lugs may be release with a pressure increase within the tubing such that the locking lugs release and the tool is released into the well bore.
  • In an embodiment shown in FIG. 3, the tool may be a hydrajetting tool 30. The hydrajetting tool 30 may have one or more locking lugs 32 for lockingly engaging the locking receptacles on the profile nipple. Disposed within the hydrajetting tool 30 may be fishing profile insets 44. These insets 44 may be used to allow a fishing apparatus to be passed through the interior of the tubing string and into the hydrajetting tool 30, engage the hydrajetting tool 30 and remove it from profile nipple. The hydrajetting tool 30 may contain a check ball 36, which may be configured in a single or double check configuration. A ball sub check 34 may be disposed above the check ball 36 and act as a valve seat to prevent back flow of any fluid through the hydrajetting tool 30. In an embodiment with a double check valve configuration, there may be two check balls and associated ball sub checks arranged in series to provide a double check valve. A ball cage 38 may be disposed on one side of the check ball 36 opposite the ball sub check 34. The ball cage 38 may limit the movement of the check ball 36 when the check ball 36 is not seated on the ball sub check 34. One or more hydrajetting nozzles 40 may be disposed on the end of the hydrajetting tool 30. In an embodiment, the hydrajetting tool 30 may have between one and thirty hydrajetting nozzles 40. The number and diameter of the hydrajetting nozzles 40 may depend on the number and size of the perforations desired the well bore diameter, the casing size, and the composition of the subterranean formation. An optional downjet 42 for washing down the well bore may be included on a hydrajetting tool 30 depending on the treatment operation being conducted.
  • In another embodiment shown in FIG. 4, the tool may be a perforating gun 50. The perforating gun may have locking lugs 52 to lockingly engage the locking receptacles on the profile nipple. Disposed within the perforating gun 50 may be fishing profile insets 54. These insets 54 may be used to allow a fishing apparatus to be passed through the interior of the tubing string and into the perforating gun 50 to engage the perforating gun 50 and remove it from profile nipple. A piston 58 may be disposed within the perforating gun 50. One or more shear pins 56 may be disposed within the body of the perforating gun 50 and extend into the piston 58. The shear pins 56 may be designed to shear at a specific shear force. The shear force may be provided by fluid pressure supplied to the top side of the piston 58, which may be supplied with fluid and pressure through a hydraulic workover unit. A firing pin 60 may be connected to the piston such that when the piston 58 moves in response to a fluid pressure, the firing pin 60 is driven towards an explosive initiator 62. The explosive initiator 62 may contain the explosive charges designed to form perforations in the surrounding casing and subterranean formation. In an embodiment, the explosive initiator 62 may contain shaped charges for forming perforations. There may be between 1 and 50 charges for creating perforations depending on the number of perforations desired.
  • In an embodiment shown in FIG. 5, the tool may be a washing tool 70 for washing down the tubing in the event of a wash out or removing debris from the well bore following a treatment operation. The washing tool 70 may have one or more locking lugs 72 for lockingly engaging the locking receptacles on a profile nipple. Disposed within the washing tool 30 may be fishing profile insets 74. These insets 74 may be used to allow a fishing apparatus to be passed through the interior of the tubing string and into the washing tool 70 to engage the washing tool 70 and remove it from profile nipple. The washing tool 70 may contain a check ball 78 for creating a check valve. A ball sub check 76 may be disposed above the check ball 78 and act as a valve seat to prevent back flow of any fluid through the washing tool 70. In another embodiment, there may be two check balls and two ball sub checks arranged in series for creating a double check valve configuration in the washing tool 70. A ball cage 80 may be disposed on one side of the check ball 78 opposite the ball sub check 76. The ball cage 80 may limit the movement of the check ball 78 when the check ball 78 is not seated on the ball sub check 76.
  • In certain embodiments, the methods disclosed herein may be used to perform a treatment in several different intervals within a subterranean well bore. In an embodiment, the treatment may be a perforating operation, a fracturing operation, or both. The methods of the present invention may be used to treat subterranean formations in such a way that, among other things, may allow for more time- and cost-efficient treatments of multiple zones of certain subterranean formations. In certain embodiments, such improvements in time and cost efficiency may be the result of performing the methods of the present invention in a single trip into the well bore.
  • In some embodiments, the methods of the present invention provide a method of treating a well bore in a single trip, the method comprising: inserting a tubing string into a subterranean formation comprising a well bore, wherein the tubing string has a locking device disposed on an end; positioning a workover tool in a first zone of the subterranean formation, wherein the workover tool engages the locking device; creating or enhancing one or more perforations in a first zone of a subterranean formation using the workover tool; positioning the tubing string in a second zone of the subterranean formation; introducing a fracturing fluid into the first zone of the subterranean formation at a rate and pressure sufficient to create or enhance one or more fractures in the subterranean formation; isolating the first zone of the subterranean formation from the second zone of the subterranean formation; and creating or enhancing one or more perforations in the second zone of the subterranean formation using the workover tool. The term “zone” as used herein simply refers to a portion of the formation and does not imply a particular geological strata or composition
  • In certain embodiments, the methods of the present invention provide a method that comprises introducing a tubing string into a subterranean formation comprising a well bore, creating or enhancing one or more perforations in a first zone of a subterranean formation, introducing a fracturing fluid into the first zone of the subterranean formation at a rate and pressure sufficient to create or enhance one or more fractures in the subterranean formation, and isolating the first zone of the subterranean formation from a second zone of the subterranean formation.
  • In certain embodiments as shown in FIGS. 6A through 6D, the methods of the present invention comprise a method of treating a well bore in a single trip, the method comprising: using a hydraulic workover unit to introduce a tubing string 16 into a subterranean formation 22 comprising a well bore 10, wherein the tubing string 16 has a locking device 18 disposed on an end; introducing a logging tool into a well bore to position the end of the tubing string 16; engaging a hydrajetting tool 30 with the locking device 18 in a first zone of the subterranean formation 22; creating or enhancing one or more perforations 60 in the first zone of the subterranean formation 22 using the hydrajetting tool 30; positioning a hydrajetting tool 30 in a second zone of the subterranean formation 22; pumping a fluid at a rate and pressure sufficient to create or enhance one or more fractures 62 in the subterranean formation 22; and isolating the first zone from the second zone.
  • Any suitable tool or apparatus that may be used to create or enhance perforations in the subterranean formation may be introduced into and removed from the well bore using a variety of methods. In an embodiment, a tubing string may be introduced into the well bore using any means capable of disposing a tubing string within a well bore, including those known in the art. The tubing string may be disposed within the well bore such that the depth of the end of the tubing string is correlated with a specific formation zone to be treated. A variety of depth correlation techniques may be used to help ensure that the end of the tubing is located adjacent to a desired zone. In one embodiment, a logging tool may be used to correlate the depth of the tubing string in the well bore. In one embodiment, the logging tool may be a collar locator tool that may be run in with the tubing string to sense the collars in the casing, allowing a determination of the depth in the well. In another embodiment, a bridge plug may be set with a wireline below the zones of interest followed by tagging the bridge plug with the tubing string and correlating the depth with depth counters. In still another embodiment, the tubing may be disposed in the well bore and a collar locator tool may be utilized inside the tubing string to locate the joints in jointed tubing, if jointed tubing is used. In yet another embodiment, the logging tool may be a wire-line gamma ray logging tool that may be run inside the tubing and used to correlate the depth and position the end of the tubing string with a desired formation interval.
  • In order to ensure proper positioning of the tubing string and work tools during a treatment operation, a fluid may be circulated down the tubing string and out through the annulus between the tubing string and the casing prior to performing a depth correlation. This circulation may cool the tubing string and well bore, causing thermal contraction of the tubing string. The effect of thermal contraction on the placement of the end of the tubing string may increase as the depth of the well increases.
  • In some embodiments as shown in FIGS. 6A and 6B, the tubing string 16 may have a profile nipple 18 for connecting a variety of treatment tools disposed on an end of the tubing string 16. The profile nipple 18 may be introduced into the well bore 10 already attached to the tubing string 16. In some embodiments, the tool or apparatus may be introduced into the well bore 10 by any means capable of disposing the tool within the well bore 10 and engaging the tool with the tubing string 16. Methods of disposing the tool within the well bore 10 may include, but are not limited to, pumping the tool through the tubing string to engage the tool with the profile nipple as shown in FIG. 6B, and placing the tool into an engagement with the profile nipple using a wireline, a slickline, or coiled tubing. In another embodiment, a tool may be disposed in the well bore by engaging the tool with the profile nipple at the surface and then placing the tubing string with the attached profile nipple with the attached tool into the well bore.
  • Following placement of the tubing string and the tool or apparatus to be used to create or enhance perforations in a first zone of the subterranean formation, one or more such perforations may be created or enhanced in the subterranean formation. The perforations may be formed using a variety of methods, including but not limited to, using a hydrajetting tool or a perforating gun.
  • In an embodiment shown in FIG. 6B, one or more perforations 60 may be formed using a hydrajetting tool 30 engaged to the profile nipple 18 on the end of the tubing string 16. In this embodiment, an abrasive fluid may be pumped through high-pressure jets and directed at the casing 12, the cement, and the formation 22. The abrasive fluid may be a carrier fluid containing a solid material, which may be any material with abrasive properties and may generally range from 70/170 to 20/40 mesh. In an embodiment, the solid material may be sand, a metal oxide, or any other material with abrasive properties. The abrasive fluid may be pumped through the tubing string at a predetermined rate for a specific period of time. The time required to perforate varies depending on, but not limited to, the solid material concentration in the carrier fluid, the abrasive fluid pump rate, the number of strings of tubing or casing that must perforated, their respective thicknesses, and the formation composition. In an embodiment, a perforation 60 created using a hydrajetting tool 30 may be approximately three times the nozzle diameter or larger. The fluid pumped through the hydrajetting tool 30 may be returned to the surface or the top of the well by flowing in the annular space between the tubing string 16 and the casing 12. A choke device may be present in an embodiment in which a hydraulic workover unit 20 is used to collect and recirculate the abrasive fluid to the hydrajetting tool 30. The hydrajetting tool 30 may be retrieved after the perforations 60 are formed. In an embodiment, a wireline, slickline, or coiled tubing may be used to engage the fishing profile in the hydrajetting tool 30, release it from its engagement with the profile nipple 18, and return it to the top of the well. In another embodiment, a fluid may be circulated down through the annular space between the casing 12 and the tubing string 16 and up through the interior of the tubing string 16 as a sufficient pressure to return the hydrajetting tool 30 to the surface, as shown in FIG. 6C.
  • In another embodiment, a perforating gun engaged in the profile nipple may be used to create perforations in the subterranean formation. In this embodiment, a fluid pressure may be used to activate the perforating gun once the tubing string and perforating gun tool are properly placed within the well bore. As shown in FIG. 4, a pressure applied to the top of the piston 58, which may be done by pumping or pressurizing a fluid within the tubing string, may be used to move the piston 58 towards the explosive initiator 62. In this embodiment, shear pins 56 may be used to maintain the piston 58 in a fixed position until a sufficient pressure is provided to the top of the piston 58 to cause the shear pins 56 to fail. At this point, the piston 58 may move downward and drive the firing pin 60 into the explosive initiator 62, causing the perforating charges to fire. There may be one or more perforating charges, which may be for example, shaped charges, capable of creating one or more perforations through the casing, cement, and into the formation. In an embodiment in which a perforating gun is used to create perforations in the well bore, the perforating gun may be retrieved after the perforations are formed. In an embodiment, a wireline, slickline, or coiled tubing may be used to engage the fishing profile in the perforating gun, releasing it from its engagement with the profile nipple. The perforating gun may then be returned to the top of the well using the wireline, slickline, coiled tubing, fluid suction on the top of the perforating gun tool, or any combination thereof. In this embodiment, a new tool may be engaged into the profile nipple. The new tool may be a hydrajetting tool, a washing tool, or any other tool capable of providing a fluid to the end of the tubing string located at or near the perforations.
  • As shown in FIGS. 6A through 6D, the tubing string 16 may be repositioned to another interval in the well bore 10 after perforations 60 are created in the well bore 10. Such a repositioning may be necessary, inter alia, to allow for the fracturing step described below and/or the perforation of additional zone(s). In an embodiment, the tubing string 16 may be repositioned to a second zone in which it is desirable to create perforations. In certain embodiments, the second zone may be located uphole from the first zone. In an embodiment, a logging tool may be used to correlate the tubing string depth with a known interval of interest, as described above. In another embodiment, the tubing string may remain at the perforation location and be moved after a treatment operation.
  • Suitable fracturing fluids for use in the present invention generally comprise a base fluid, a suitable gelling agent, and proppant particulates. Optionally, other components may be included if desired, as recognized by one skilled in the art with the benefit of this disclosure. For example, the fluids used in the present invention optionally may comprise one or more additional additives known in the art, including, but not limited to, fluid loss control additives, gel stabilizers, gas, salts (e.g., KCl), pH-adjusting agents (e.g., buffers), corrosion inhibitors, dispersants, flocculants, acids, foaming agents, antifoaming agents, H2S scavengers, lubricants, oxygen scavengers, weighting agents, scale inhibitors, surfactants, catalysts, clay control agents, biocides, friction reducers, particulates (e.g., proppant particulates, gravel particulates), combinations thereof, and the like. For example, a gel stabilizer compromising sodium thiosulfate may be included in certain treatment fluids of the present invention. Individuals skilled in the art, with the benefit of this disclosure, will recognize the types of additives that may be suitable for a particular application of the present invention. For example, particulates may be included in the treatment fluids of the present invention in certain types of subterranean operations, including fracturing operations, gravel-packing operations, and the like.
  • The aqueous base fluid used in the treatment fluids of the present invention may comprise fresh water, saltwater (e.g., water containing one or more salts dissolved therein), brine, seawater, or combinations thereof. Generally, the water may be from any source, provided that it does not contain components that might adversely affect the stability and/or performance of the treatment fluids of the present invention, for example, copper ions, iron ions, or certain types of organic materials (e.g., lignin). In certain embodiments, the density of the aqueous base fluid can be increased, among other purposes, to provide additional particle transport and suspension in the treatment fluids of the present invention. In certain embodiments, the pH of the aqueous base fluid may be adjusted (e.g., by a buffer or other pH adjusting agent), among other purposes, to activate a crosslinking agent, and/or to reduce the viscosity of the treatment fluid (e.g., activate a breaker, deactivate a crosslinking agent). In these embodiments, the pH may be adjusted to a specific level, which may depend on, among other factors, the types of gelling agents, crosslinking agents, and/or breakers included in the treatment fluid. One of ordinary skill in the art, with the benefit of this disclosure, will recognize when such density and/or pH adjustments are appropriate.
  • The gelling agents utilized in the present invention may comprise any polymeric material capable of increasing the viscosity of an aqueous fluid. In certain embodiments, the gelling agent may comprise polymers that have at least two molecules that are capable of forming a crosslink in a crosslinking reaction in the presence of a crosslinking agent, and/or polymers that have at least two molecules that are so crosslinked (i.e., a crosslinked gelling agent). The gelling agents may be naturally-occurring, synthetic, or a combination thereof. In certain embodiments, suitable gelling agents may comprise polysaccharides, and derivatives thereof that contain one or more of these monosaccharide units: galactose, mannose, glucoside, glucose, xylose, arabinose, fructose, glucuronic acid, or pyranosyl sulfate. Examples of suitable polysaccharides include, but are not limited to, guar gums (e.g., hydroxyethyl guar, hydroxypropyl guar, carboxymethyl guar, carboxymethylhydroxyethyl guar, and carboxymethylhydroxypropyl guar (“CMHPG”)), cellulose derivatives (e.g., hydroxyethyl cellulose, carboxyethylcellulose, carboxymethylcellulose, and carboxymethylhydroxyethylcellulose), and combinations thereof. In certain embodiments, the gelling agents comprise an organic carboxylated polymer, such as CMHPG. In certain embodiments, the derivatized cellulose is a cellulose grafted with an allyl or a vinyl monomer, such as those disclosed in U.S. Pat. Nos. 4,982,793; 5,067,565; and 5,122,549, the relevant disclosures of which are incorporated herein by reference. Additionally, polymers and copolymers that comprise one or more functional groups (e.g., hydroxyl, cis-hydroxyl, carboxylic acids, derivatives of carboxylic acids, sulfate, sulfonate, phosphate, phosphonate, amino, or amide groups) may be used.
  • The gelling agent may be present in the treatment fluids of the present invention in an amount sufficient to provide the desired viscosity. In some embodiments, the gelling agents may be present in an amount in the range of from about 0.12% to about 2.0% by weight of the treatment fluid. In certain embodiments, the gelling agents may be present in an amount in the range of from about 0.18% to about 0.72% by weight of the treatment fluid.
  • In those embodiments of the present invention wherein it is desirable to crosslink the gelling agent, the treatment fluid may comprise one or more of the crosslinking agents. The crosslinking agents may comprise a metal ion that is capable of crosslinking at least two molecules of the gelling agent. Examples of suitable crosslinking agents include, but are not limited to, borate ions, zirconium IV ions, titanium IV ions, aluminum ions, antimony ions, chromium ions, iron ions, copper ions, and zinc ions. These ions may be provided by providing any compound that is capable of producing one or more of these ions; examples of such compounds include, but are not limited to, boric acid, disodium octaborate tetrahydrate, sodium diborate, pentaborates, ulexite, colemanite, zirconium lactate, zirconium triethanol amine, zirconium lactate triethanolamine, zirconium carbonate, zirconium acetylacetonate, zirconium maleate, zirconium citrate, zirconium diisopropylamine lactate, zirconium glycolate, zirconium triethanol amine glycolate, zirconium lactate glycolate, titanium lactate, titanium malate, titanium citrate, titanium ammonium lactate, titanium triethanolamine, and titanium acetylacetonate, aluminum lactate, aluminum citrate, antimony compounds, chromium compounds, iron compounds, copper compounds, zinc compounds, and combinations thereof. In certain embodiments of the present invention, the crosslinking agent may be formulated to remain inactive until it is “activated” by, among other things, certain conditions in the fluid (e.g., pH, temperature, etc.) and/or contact with some other substance. In some embodiments, the crosslinking agent may be delayed by encapsulation with a coating (e.g., a porous coating through which the breaker may diffuse slowly, or a degradable coating that degrades downhole) that delays the release of the crosslinking agent until a desired time or place. The choice of a particular crosslinking agent will be governed by several considerations that will be recognized by one skilled in the art, including but not limited to the following: the type of gelling agent included, the molecular weight of the gelling agent(s), the pH of the treatment fluid, temperature, and/or the desired time for the crosslinking agent to crosslink the gelling agent molecules.
  • When included, suitable crosslinking agents may be present in the treatment fluids of the present invention in an amount sufficient to provide, inter alia, the desired degree of crosslinking between molecules of the gelling agent. In certain embodiments, the crosslinking agent may be present in the treatment fluids of the present invention in an amount in the range of from about 0.0005% to about 0.2% by weight of the treatment fluid. In certain embodiments, the crosslinking agent may be present in the treatment fluids of the present invention in an amount in the range of from about 0.001% to about 0.05% by weight of the treatment fluid. One of ordinary skill in the art, with the benefit of this disclosure, will recognize the appropriate amount of crosslinking agent to include in a treatment fluid of the present invention based on, among other things, the temperature conditions of a particular application, the type of gelling agents used, the molecular weight of the gelling agents, the desired degree of viscosification, and/or the pH of the treatment fluid.
  • In some embodiments, the fracturing fluid may comprise a plurality of proppant particulates, inter alia, to stabilize the fractures created or enhanced. Particulates suitable for use in the present invention may comprise any material suitable for use in subterranean operations. Suitable materials for these particulates may include, but are not limited to, sand, bauxite, ceramic materials, glass materials, polymer materials, TEFLON® (polytetrafluoroethylene) materials, nut shell pieces, cured resinous particulates comprising nut shell pieces, seed shell pieces, cured resinous particulates comprising seed shell pieces, fruit pit pieces, cured resinous particulates comprising fruit pit pieces, wood, composite particulates, and combinations thereof. Suitable composite particulates may comprise a binder and a filler material wherein suitable filler materials include silica, alumina, fumed carbon, carbon black, graphite, mica, titanium dioxide, meta-silicate, calcium silicate, kaolin, talc, zirconia, boron, fly ash, hollow glass microspheres, solid glass, and combinations thereof. The mean particulate size generally may range from about 2 mesh to about 400 mesh on the U.S. Sieve Series; however, in certain circumstances, other mean particulate sizes may be desired and will be entirely suitable for practice of the present invention. In particular embodiments, preferred mean particulates size distribution ranges are one or more of 6/12, 8/16, 12/20, 16/30, 20/40, 30/50, 40/60, 40/70, or 50/70 mesh. It should be understood that the term “particulate,” as used in this disclosure, includes all known shapes of materials, including substantially spherical materials, fibrous materials, polygonal materials (such as cubic materials), and mixtures thereof. Moreover, fibrous materials, that may or may not be used to bear the pressure of a closed fracture, may be included in certain embodiments of the present invention. In certain embodiments, the particulates included in the treatment fluids of the present invention may be coated with any suitable resin or tackifying agent known to those of ordinary skill in the art. In certain embodiments, the particulates may be present in the fluids of the present invention in an amount in the range of from about 0.5 pounds per gallon (“ppg”) to about 30 ppg by volume of the treatment fluid.
  • In an embodiment, a fracturing fluid carrying the proppant may be pumped down the annulus between the casing and the tubing string and a base fluid may be pumped down through the tubing. The base fluid may contain a gel breaker that may be mixed with the fracturing fluid at or near the end of the tubing string, which may be at or near the perforations in the well bore. In this embodiment, the dual pumping scheme comprising two fluids being transported through the annulus and the tubing string may allow for thermal cooling of the fracturing fluid by the fluid in the tubing string, helping to prevent premature breakdown of the fracturing fluid in a HTHP well. Fracturing of the subterranean formation through the perforations may continue until the desired fractures in the formation have been achieved.
  • In certain embodiments, the fracturing fluid may comprise a gelling agent, which may also be known as a viscosifying agent. As used herein, the term “gelling agents” refer to a material capable of increasing the viscosity of the fracturing fluid. A fluid that comprises a gelling agent may be referred to herein as a viscosified fluid, a gel, or an equivalent term. Suitable gelling agents for specific applications are known to one skilled in the arts. Examples of suitable gelling agents include, without limitation, natural or derivatized polysaccharides that are soluble, dispersible, or swellable in an aqueous liquid, modified celluloses and derivatives thereof, and biopolymers. Synthetic gelling agents may also be used if desired.
  • In an embodiment, a base fluid transported through the tubing string may contain a gel breaker, which may be useful for reducing the viscosity of the viscosified fracturing fluid at a specified time. A gel breaker may comprise any compound capable of lowering the viscosity of a viscosified fluid. The term “break” (and its derivatives) as used herein refers to a reduction in the viscosity of the viscosified treatment fluid, e.g., by the breaking or reversing of the crosslinks between polymer molecules or some reduction of the size of the gelling agent polymers. No particular mechanism is implied by the term
  • Suitable gel breaking agents for specific applications and gelled fluids are known to one skilled in the arts. Nonlimiting examples of suitable breakers include oxidizers, peroxides, enzymes, acids, and the like. Some viscosified fluids also may break with sufficient exposure of time and temperature.
  • Without being limited by a particular theory or mechanism of action, it is nevertheless currently believed that using a dual pumping scheme may extend the gel viscosity life by preventing premature interaction between the gelled fracturing fluid and a base fluid containing a gel breaker. Preventing such interaction may be important in HTHP wells in which high temperatures may increase the reaction rate at which the gel breaks. HTHP wells may typically be deep wells resulting in an increased distance over which the interaction between the gelled fluid and the base fluid containing a gel breaker may occur. By keeping the two separate until at or near the point of introduction into the formation, the effectiveness of the fracturing fluid may be increased. In an embodiment in which a gelled fracturing fluid and a base fluid containing a gel breaker are kept separate during transport into the well, the gel breaker may be an aggressive gel breaker. The use of an aggressive gel beaker may allow for high pressure, high rate fracturing with a reduced time to break the gel after fracturing and return the fracturing fluids from the subterranean formation.
  • In certain embodiments as shown in FIGS. 6D through 6F, after one or more fractures have been created or enhanced in the first zone of the subterranean formation 22, it may be desirable to isolate the first zone from one or more additional zones. Such an isolation may be performed by any means known to one of ordinary skill in the art. In certain embodiments, such an isolation may be performed by introducing a treatment fluid comprising a plurality of proppant particulates into at least a portion of the region of the well bore between the first zone and any additional zones. The introduction of a plurality of proppant particulates may act to form a proppant particulate bridge 68 across the casing, effectively isolating the interval below the bridge 68 from the interval above the bridge 68. Other suitable methods of performing such an isolation may comprise the use of through tubing bridge plugs, dump bailer set plugs (e.g., chemical plugs, proppant plugs, etc.), ball sealers, or any other type of plugging device capable of being set or passed through the tubing string to be placed in the well bore. In another embodiment, a moveable bridge plug that may be set and reset using a wireline, slickline, coiled tubing or a combination thereof may be positioned in the well bore prior to initially disposing the tubing string in the well bore. After an interval has been fractured, the bridge plug may be repositioned using a wireline, slickline, coiled tubing, or any combination thereof passed through the tubing string.
  • As shown in FIGS. 6A through 6G, the steps described herein may be repeated for multiple intervals in the subterranean formation 22. For example, following the isolation of the first zone from additional zone(s), one or more perforations 64 may be created or enhanced in a second zone. Such perforations 64 may be introduced, as described above, by the use of a hydrajetting tool 30, a perforating gun, or any other means of creating perforations. After perforation of the second zone is completed, the tubing string 16 and/or tool or apparatus used to create or enhance the perforation(s) may then be moved to a third zone of the subterranean formation. A fracturing fluid may then be pumped down the annulus, optionally with the simultaneous introduction of a base fluid through the tubing string, at a rate and pressure sufficient to create or enhance one or more fractures in the second zone of the subterranean formation. The second zone may then be isolated from addition zone(s) as described above, and the methods may then be repeated for a third zone, etc. Any number of zones may be perforated and treated by repeating the process as many times as necessary.
  • In an embodiment, a washing tool may be used at any point in the method to clean out the well bore of any debris, including any proppant bridges placed to isolate one interval from another. In this embodiment, a washing tool may be used to circulate a fluid through the tubing string and to the top of the well through the annulus between the casing and the tubing string. In another embodiment, a fluid may be circulated down the annulus between the casing and tubing string and back to the top of the well through the tubing.
  • An embodiment of the present invention may provide a method of treating a well bore in a single trip, the method comprising inserting a tubing string into a subterranean formation comprising a well bore, wherein the tubing string has a locking device disposed on an end; positioning a workover tool in a first zone of the subterranean formation, wherein the workover tool engages the locking device; creating or enhancing one or more perforations in a first zone of a subterranean formation using the workover tool; positioning the tubing string in a second zone of the subterranean formation; introducing a fracturing fluid into the first zone of the subterranean formation at a rate and pressure sufficient to create or enhance one or more fractures in the subterranean formation; isolating the first zone of the subterranean formation from the second zone of the subterranean formation; and creating or enhancing one or more perforations in the second zone of the subterranean formation using the workover tool.
  • Another embodiment of the present invention may provide a method of treating a well bore in a single trip, the method comprising using a hydraulic workover unit to introduce a tubing string into a subterranean formation comprising a well bore, wherein the tubing string has a locking device disposed on an end; introducing a logging tool into a well bore to position the end of the tubing string; engaging a hydrajetting tool with the locking device in a first zone of the subterranean formation; creating or enhancing one or more perforations in the first zone of the subterranean formation using the hydrajetting tool; positioning a hydrajetting tool in a second zone of the subterranean formation; pumping a fluid at a rate and pressure sufficient to create or enhance one or more fractures in the subterranean formation; and isolating the first zone from the second zone.
  • Still another embodiment of the present invention may provide a downhole tool system comprising a profile nipple disposed on a tubing string, where the profile nipple comprises a locking receptacle; and a tool assembly, where the tool assembly has a locking lug, wherein the locking lug engages the locking lug receptacle, wherein the tool assembly may be passed through the tubing string to engage the profile nipple.
  • To facilitate a better understanding of the present invention, the following examples of the preferred embodiments are given. In no way should the following examples be read to limit, or define, the scope of the invention.
  • EXAMPLE 1
  • In order to demonstrate the methods disclosed herein, a set of tests were conducted in Michigan in multiple shallow, low pressure, substantially vertical wells. In these tests, a hydrajetting tool was deployed from surface through a tubing string. The end of the tubing was placed at a depth corresponding to the target interval for perforating and fracturing. The end of the tubing contained a seat (e.g., a profile nipple) to prevent the hydra-jetting tool from passing completely through the end of tubing while allowing the hydra-jetting tool to have the jets exposed to the casing. The hydra-jetting tool was placed in the tubing and allowed to pass through the tubing until it was disposed in the end of tubing, where it engaged the seat. The hydra-jetting tool was engaged to form perforations in the casing. Once the perforations were formed, the fluid in the well was reverse circulated (i.e., fluid was pumped down the annulus between the casing and the tubing string to return to the surface through the interior of the tubing string). The reverse circulation forced the hydra-jetting tool to be lifted back to surface through the tubing string where it was captured by a valve and short joint of pipe.
  • The well bore was then fractured by pumping a fracturing fluid through the tubing string and allowing it to pass through the seat. A sand plug was then placed in the casing at the target interval by passing a treatment fluid containing sand down the tubing string and allowing the sand to settle in the well bore, covering the perforations which were fractured. The tubing string was then moved to the next target zone, which in this test was above the first target zone, and the process was repeated.
  • EXAMPLE 2
  • In order to demonstrate the methods disclosed herein, another set of tests were conducted in Michigan in multiple shallow, low pressure, substantially vertical wells. These tests were substantially similar to those tests described in Example 1 with the exception that a retrievable bridge plug was used between target zones rather than the placement of one or more sand plugs.
  • In these tests, a hydra-jetting tool was deployed from surface through a tubing string. The end of the tubing was placed at a depth corresponding to the target interval for perforating and fracturing. The end of the tubing contained a seat (e.g., a profile nipple) to prevent the hydra-jetting tool from passing completely through the end of tubing while allowing the hydra-jetting tool to have the jets exposed to the casing. The hydra-jetting tool was placed in the tubing and allowed to pass through the tubing until it was disposed in the end of tubing, where it engaged the seat. The hydra-jetting tool was engaged to form perforations in the casing. Once the perforations were formed, the fluid in the well was reverse circulated (i.e., fluid was pumped down the annulus between the casing and the tubing string to return to the surface through the interior of the tubing string). The reverse circulation forced the hydra-jetting tool to be lifted back to surface through the tubing string where it was captured by a valve and short joint of pipe.
  • The well bore was then fractured by pumping a fracturing fluid through the tubing string and allowing it to pass through the seat. A retrievable bridge plug was then placed in the casing at the target interval by passing the retrievable bridge plus through the tubing string and setting the bridge plug in the well bore above the target zone, isolating the perforations which were fractured. The tubing string was then moved to the next target zone, which in this test was above the first target zone, and the process was repeated.
  • Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present invention. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Therefore, the present invention is well-adapted to carry out the objects and attain the ends and advantages mentioned as well as those which are inherent therein. While the invention has been depicted and described by reference to exemplary embodiments of the invention, such a reference does not imply a limitation on the invention, and no such limitation is to be inferred. The invention is capable of considerable modification, alternation, and equivalents in form and function, as will occur to those ordinarily skilled in the pertinent arts and having the benefit of this disclosure. The depicted and described embodiments of the invention are exemplary only, and are not exhaustive of the scope of the invention. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood as referring to the power set (the set of all subsets) of the respective range of values, and set forth every range encompassed within the broader range of values. Consequently, the invention is intended to be limited only by the spirit and scope of the appended claims, giving full cognizance to equivalents in all respects. Moreover, the indefinite articles “a” and “an”, as used in the claims, are defined herein to mean to one or more than one of the element that it introduces. The terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee.

Claims (22)

1. A method of treating a well bore in a single trip, the method comprising:
inserting a tubing string into a subterranean formation comprising a well bore, wherein the tubing string has a locking device disposed on an end;
positioning a workover tool in a first zone of the subterranean formation, wherein the workover tool engages the locking device;
creating or enhancing one or more perforations in a first zone of a subterranean formation using the workover tool;
positioning the tubing string in a second zone of the subterranean formation;
introducing a fracturing fluid into the first zone of the subterranean formation at a rate and pressure sufficient to create or enhance one or more fractures in the subterranean formation;
isolating the first zone of the subterranean formation from the second zone of the subterranean formation; and
creating or enhancing one or more perforations in the second zone of the subterranean formation using the workover tool.
2. The method of claim 1 wherein inserting a tubing string into a well bore comprises using a hydraulic workover unit to introduce the tubing string into the well bore under pressure.
3. The method of claim 1 wherein the tubing string comprises jointed tubing.
4. The method of claim 1 wherein positioning the workover tool or positioning the tubing string comprises using a logging tool to correlate the end with a depth in the well.
5. The method of claim 1 wherein introducing a fracturing fluid comprises:
pumping a fracturing fluid comprising a plurality of proppant particulates between the tubing string and the well bore; and
simultaneously pumping a base fluid through the tubing string.
6. The method of claim 1 wherein isolating the first zone comprises introducing a plurality of proppant particulates into the well bore between the first zone and the second zone to form a bridge.
7. The method of claim 1 wherein the workover tool comprises at least one tool selected from the group consisting of: a hydrajetting tool, a perforating gun, a washing tool.
8. The method of claim 1 wherein the workover tool may be positioned in the subterranean formation using a method comprising at least one method selected from the group consisting of: pumping through the tubing string, placing with a wireline, placing with a slickline, placing with a coiled tubing string, and dropping through the tubing string.
9. The method of claim 4 further comprising circulating a fluid through the tubing string prior to positioning the tubing string using a logging tool.
10. A method of treating a well bore in a single trip, the method comprising:
using a hydraulic workover unit to introduce a tubing string into a subterranean formation comprising a well bore, wherein the tubing string has a locking device disposed on an end;
introducing a logging tool into a well bore to position the end of the tubing string;
engaging a hydrajetting tool with the locking device in a first zone of the subterranean formation;
creating or enhancing one or more perforations in the first zone of the subterranean formation using the hydrajetting tool;
positioning a hydrajetting tool in a second zone of the subterranean formation;
pumping a fluid at a rate and pressure sufficient to create or enhance one or more fractures in the subterranean formation; and
isolating the first zone from the second zone.
11. The method of claim 10 wherein the pumping a fluid comprises pumping a fracturing fluid comprising a plurality of proppant particulates between the tubing string and the well bore while simultaneously pumping a base fluid through the tubing string.
12. The method of claim 10 wherein the second zone is located above the first zone.
13. The method of claim 10 wherein the hydrajetting tool is engaged with the locking device by using a method comprising at least one method selected from the group consisting of: pumping through the tubing string, placing with a wireline, placing with a slickline, placing with a coiled tubing string, and dropping through the tubing string.
14. The method of claim 10 further comprising:
washing the well bore using a washing device engaged with the locking device on the end of the tubing string.
15. The method of claim 10 wherein the isolating the first zone from the second zone comprises creating a proppant bridge in a casing between the first zone and the second zone.
16. The method of claim 10 wherein the isolating the first zone from the second zone comprises using a dump bailer passed through the tubing string to set a plug between the first zone and the second zone.
17. The method of claim 11 wherein the fracturing fluid comprises a gelling agent and the base fluid comprises a gel breaker.
18. A downhole tool system comprising:
a profile nipple disposed on a tubing string, wherein the profile nipple comprises a locking receptacle; and
a tool assembly, wherein the tool assembly has a locking lug, wherein the locking lug engages the locking lug receptacle, wherein the tool assembly may be passed through the tubing string to engage the profile nipple.
19. The downhole tool system of claim 18 wherein the tool assembly comprises at least one tool selected from the group consisting of: a perforating gun, and a washing tool.
20. The downhole tool system of claim 18 wherein the tool comprises a hydrajetting tool.
21. The downhole tool system of claim 20 wherein the hydrajetting tool comprises dual check valves.
22. The downhole tool system of claim 18 wherein the tool assembly may be engaged and retrieved by a wireline, coiled tubing, or a slickline.
US12/369,863 2009-02-12 2009-02-12 Method and Apparatus for Multi-Zone Stimulation Abandoned US20100200230A1 (en)

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US12/369,863 US20100200230A1 (en) 2009-02-12 2009-02-12 Method and Apparatus for Multi-Zone Stimulation
PCT/GB2010/000260 WO2010092352A2 (en) 2009-02-12 2010-02-12 Method and apparatus for multi-zone stimulation

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US20110135530A1 (en) * 2009-12-08 2011-06-09 Zhiyue Xu Method of making a nanomatrix powder metal compact
US8327931B2 (en) 2009-12-08 2012-12-11 Baker Hughes Incorporated Multi-component disappearing tripping ball and method for making the same
WO2013019390A1 (en) * 2011-08-03 2013-02-07 Halliburton Energy Services, Inc. Method for generating discrete fracture initiation sites and propagating dominant planar fractures therefrom
US8424610B2 (en) 2010-03-05 2013-04-23 Baker Hughes Incorporated Flow control arrangement and method
US8425651B2 (en) 2010-07-30 2013-04-23 Baker Hughes Incorporated Nanomatrix metal composite
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US8573295B2 (en) 2010-11-16 2013-11-05 Baker Hughes Incorporated Plug and method of unplugging a seat
US8631876B2 (en) 2011-04-28 2014-01-21 Baker Hughes Incorporated Method of making and using a functionally gradient composite tool
JP2014025239A (en) * 2012-07-26 2014-02-06 Takenaka Komuten Co Ltd Well structure for fracturing
US8776884B2 (en) 2010-08-09 2014-07-15 Baker Hughes Incorporated Formation treatment system and method
US8783365B2 (en) 2011-07-28 2014-07-22 Baker Hughes Incorporated Selective hydraulic fracturing tool and method thereof
WO2015026367A1 (en) * 2013-08-23 2015-02-26 Halliburton Energy Services, Inc. High-strength, low specific gravity, fracturing balls
WO2015038375A1 (en) * 2013-09-13 2015-03-19 TD Tools, Inc. Apparatus and method for jet perforating and cutting tool
US9022107B2 (en) 2009-12-08 2015-05-05 Baker Hughes Incorporated Dissolvable tool
US9033055B2 (en) 2011-08-17 2015-05-19 Baker Hughes Incorporated Selectively degradable passage restriction and method
US9057242B2 (en) 2011-08-05 2015-06-16 Baker Hughes Incorporated Method of controlling corrosion rate in downhole article, and downhole article having controlled corrosion rate
US9068428B2 (en) 2012-02-13 2015-06-30 Baker Hughes Incorporated Selectively corrodible downhole article and method of use
US9068447B2 (en) 2010-07-22 2015-06-30 Exxonmobil Upstream Research Company Methods for stimulating multi-zone wells
US9080098B2 (en) 2011-04-28 2015-07-14 Baker Hughes Incorporated Functionally gradient composite article
US9090955B2 (en) 2010-10-27 2015-07-28 Baker Hughes Incorporated Nanomatrix powder metal composite
US9090956B2 (en) 2011-08-30 2015-07-28 Baker Hughes Incorporated Aluminum alloy powder metal compact
US9101978B2 (en) 2002-12-08 2015-08-11 Baker Hughes Incorporated Nanomatrix powder metal compact
US9109429B2 (en) 2002-12-08 2015-08-18 Baker Hughes Incorporated Engineered powder compact composite material
US9109269B2 (en) 2011-08-30 2015-08-18 Baker Hughes Incorporated Magnesium alloy powder metal compact
US9127515B2 (en) 2010-10-27 2015-09-08 Baker Hughes Incorporated Nanomatrix carbon composite
US9133695B2 (en) 2011-09-03 2015-09-15 Baker Hughes Incorporated Degradable shaped charge and perforating gun system
US9139928B2 (en) 2011-06-17 2015-09-22 Baker Hughes Incorporated Corrodible downhole article and method of removing the article from downhole environment
US9187990B2 (en) 2011-09-03 2015-11-17 Baker Hughes Incorporated Method of using a degradable shaped charge and perforating gun system
US9187977B2 (en) 2010-07-22 2015-11-17 Exxonmobil Upstream Research Company System and method for stimulating a multi-zone well
US9227243B2 (en) 2009-12-08 2016-01-05 Baker Hughes Incorporated Method of making a powder metal compact
US9243475B2 (en) 2009-12-08 2016-01-26 Baker Hughes Incorporated Extruded powder metal compact
US9267347B2 (en) 2009-12-08 2016-02-23 Baker Huges Incorporated Dissolvable tool
US9284812B2 (en) 2011-11-21 2016-03-15 Baker Hughes Incorporated System for increasing swelling efficiency
US9322239B2 (en) 2012-11-13 2016-04-26 Exxonmobil Upstream Research Company Drag enhancing structures for downhole operations, and systems and methods including the same
US9347119B2 (en) 2011-09-03 2016-05-24 Baker Hughes Incorporated Degradable high shock impedance material
US9605508B2 (en) 2012-05-08 2017-03-28 Baker Hughes Incorporated Disintegrable and conformable metallic seal, and method of making the same
US9643144B2 (en) 2011-09-02 2017-05-09 Baker Hughes Incorporated Method to generate and disperse nanostructures in a composite material
US9643250B2 (en) 2011-07-29 2017-05-09 Baker Hughes Incorporated Method of controlling the corrosion rate of alloy particles, alloy particle with controlled corrosion rate, and articles comprising the particle
US9682425B2 (en) 2009-12-08 2017-06-20 Baker Hughes Incorporated Coated metallic powder and method of making the same
US9707739B2 (en) 2011-07-22 2017-07-18 Baker Hughes Incorporated Intermetallic metallic composite, method of manufacture thereof and articles comprising the same
US9765592B2 (en) 2012-06-06 2017-09-19 Exxonmobil Upstream Research Company Systems and methods for secondary sealing of a perforation within a wellbore casing
US9816339B2 (en) 2013-09-03 2017-11-14 Baker Hughes, A Ge Company, Llc Plug reception assembly and method of reducing restriction in a borehole
US9833838B2 (en) 2011-07-29 2017-12-05 Baker Hughes, A Ge Company, Llc Method of controlling the corrosion rate of alloy particles, alloy particle with controlled corrosion rate, and articles comprising the particle
US9856547B2 (en) 2011-08-30 2018-01-02 Bakers Hughes, A Ge Company, Llc Nanostructured powder metal compact
US9910026B2 (en) 2015-01-21 2018-03-06 Baker Hughes, A Ge Company, Llc High temperature tracers for downhole detection of produced water
US9926766B2 (en) 2012-01-25 2018-03-27 Baker Hughes, A Ge Company, Llc Seat for a tubular treating system
US10016810B2 (en) 2015-12-14 2018-07-10 Baker Hughes, A Ge Company, Llc Methods of manufacturing degradable tools using a galvanic carrier and tools manufactured thereof
US10221637B2 (en) 2015-08-11 2019-03-05 Baker Hughes, A Ge Company, Llc Methods of manufacturing dissolvable tools via liquid-solid state molding
US10240419B2 (en) 2009-12-08 2019-03-26 Baker Hughes, A Ge Company, Llc Downhole flow inhibition tool and method of unplugging a seat

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US9101978B2 (en) 2002-12-08 2015-08-11 Baker Hughes Incorporated Nanomatrix powder metal compact
US9109429B2 (en) 2002-12-08 2015-08-18 Baker Hughes Incorporated Engineered powder compact composite material
US8327931B2 (en) 2009-12-08 2012-12-11 Baker Hughes Incorporated Multi-component disappearing tripping ball and method for making the same
US9079246B2 (en) 2009-12-08 2015-07-14 Baker Hughes Incorporated Method of making a nanomatrix powder metal compact
US9022107B2 (en) 2009-12-08 2015-05-05 Baker Hughes Incorporated Dissolvable tool
US10240419B2 (en) 2009-12-08 2019-03-26 Baker Hughes, A Ge Company, Llc Downhole flow inhibition tool and method of unplugging a seat
US9227243B2 (en) 2009-12-08 2016-01-05 Baker Hughes Incorporated Method of making a powder metal compact
US20110135530A1 (en) * 2009-12-08 2011-06-09 Zhiyue Xu Method of making a nanomatrix powder metal compact
US9682425B2 (en) 2009-12-08 2017-06-20 Baker Hughes Incorporated Coated metallic powder and method of making the same
US8714268B2 (en) 2009-12-08 2014-05-06 Baker Hughes Incorporated Method of making and using multi-component disappearing tripping ball
US9243475B2 (en) 2009-12-08 2016-01-26 Baker Hughes Incorporated Extruded powder metal compact
US9267347B2 (en) 2009-12-08 2016-02-23 Baker Huges Incorporated Dissolvable tool
US8424610B2 (en) 2010-03-05 2013-04-23 Baker Hughes Incorporated Flow control arrangement and method
US9068447B2 (en) 2010-07-22 2015-06-30 Exxonmobil Upstream Research Company Methods for stimulating multi-zone wells
US9187977B2 (en) 2010-07-22 2015-11-17 Exxonmobil Upstream Research Company System and method for stimulating a multi-zone well
US8425651B2 (en) 2010-07-30 2013-04-23 Baker Hughes Incorporated Nanomatrix metal composite
US8776884B2 (en) 2010-08-09 2014-07-15 Baker Hughes Incorporated Formation treatment system and method
US9127515B2 (en) 2010-10-27 2015-09-08 Baker Hughes Incorporated Nanomatrix carbon composite
US9090955B2 (en) 2010-10-27 2015-07-28 Baker Hughes Incorporated Nanomatrix powder metal composite
US8573295B2 (en) 2010-11-16 2013-11-05 Baker Hughes Incorporated Plug and method of unplugging a seat
US9631138B2 (en) 2011-04-28 2017-04-25 Baker Hughes Incorporated Functionally gradient composite article
US9080098B2 (en) 2011-04-28 2015-07-14 Baker Hughes Incorporated Functionally gradient composite article
US8631876B2 (en) 2011-04-28 2014-01-21 Baker Hughes Incorporated Method of making and using a functionally gradient composite tool
US9926763B2 (en) 2011-06-17 2018-03-27 Baker Hughes, A Ge Company, Llc Corrodible downhole article and method of removing the article from downhole environment
US9139928B2 (en) 2011-06-17 2015-09-22 Baker Hughes Incorporated Corrodible downhole article and method of removing the article from downhole environment
US9707739B2 (en) 2011-07-22 2017-07-18 Baker Hughes Incorporated Intermetallic metallic composite, method of manufacture thereof and articles comprising the same
US8783365B2 (en) 2011-07-28 2014-07-22 Baker Hughes Incorporated Selective hydraulic fracturing tool and method thereof
US10092953B2 (en) 2011-07-29 2018-10-09 Baker Hughes, A Ge Company, Llc Method of controlling the corrosion rate of alloy particles, alloy particle with controlled corrosion rate, and articles comprising the particle
US9833838B2 (en) 2011-07-29 2017-12-05 Baker Hughes, A Ge Company, Llc Method of controlling the corrosion rate of alloy particles, alloy particle with controlled corrosion rate, and articles comprising the particle
US9643250B2 (en) 2011-07-29 2017-05-09 Baker Hughes Incorporated Method of controlling the corrosion rate of alloy particles, alloy particle with controlled corrosion rate, and articles comprising the particle
WO2013019390A1 (en) * 2011-08-03 2013-02-07 Halliburton Energy Services, Inc. Method for generating discrete fracture initiation sites and propagating dominant planar fractures therefrom
US8919443B2 (en) 2011-08-03 2014-12-30 Halliburton Energy Services, Inc. Method for generating discrete fracture initiation sites and propagating dominant planar fractures therefrom
US9057242B2 (en) 2011-08-05 2015-06-16 Baker Hughes Incorporated Method of controlling corrosion rate in downhole article, and downhole article having controlled corrosion rate
US9033055B2 (en) 2011-08-17 2015-05-19 Baker Hughes Incorporated Selectively degradable passage restriction and method
US9856547B2 (en) 2011-08-30 2018-01-02 Bakers Hughes, A Ge Company, Llc Nanostructured powder metal compact
US9802250B2 (en) 2011-08-30 2017-10-31 Baker Hughes Magnesium alloy powder metal compact
US9109269B2 (en) 2011-08-30 2015-08-18 Baker Hughes Incorporated Magnesium alloy powder metal compact
US9925589B2 (en) 2011-08-30 2018-03-27 Baker Hughes, A Ge Company, Llc Aluminum alloy powder metal compact
US9090956B2 (en) 2011-08-30 2015-07-28 Baker Hughes Incorporated Aluminum alloy powder metal compact
US9643144B2 (en) 2011-09-02 2017-05-09 Baker Hughes Incorporated Method to generate and disperse nanostructures in a composite material
US9187990B2 (en) 2011-09-03 2015-11-17 Baker Hughes Incorporated Method of using a degradable shaped charge and perforating gun system
US9347119B2 (en) 2011-09-03 2016-05-24 Baker Hughes Incorporated Degradable high shock impedance material
US9133695B2 (en) 2011-09-03 2015-09-15 Baker Hughes Incorporated Degradable shaped charge and perforating gun system
US9284812B2 (en) 2011-11-21 2016-03-15 Baker Hughes Incorporated System for increasing swelling efficiency
US9926766B2 (en) 2012-01-25 2018-03-27 Baker Hughes, A Ge Company, Llc Seat for a tubular treating system
US9068428B2 (en) 2012-02-13 2015-06-30 Baker Hughes Incorporated Selectively corrodible downhole article and method of use
WO2013126256A1 (en) * 2012-02-22 2013-08-29 Schlumberger Canada Limited High pressure jet perforation system
US8985209B2 (en) 2012-02-22 2015-03-24 Schlumberger Technology Corporation High pressure jet perforation system
US9605508B2 (en) 2012-05-08 2017-03-28 Baker Hughes Incorporated Disintegrable and conformable metallic seal, and method of making the same
US9765592B2 (en) 2012-06-06 2017-09-19 Exxonmobil Upstream Research Company Systems and methods for secondary sealing of a perforation within a wellbore casing
JP2014025239A (en) * 2012-07-26 2014-02-06 Takenaka Komuten Co Ltd Well structure for fracturing
US9322239B2 (en) 2012-11-13 2016-04-26 Exxonmobil Upstream Research Company Drag enhancing structures for downhole operations, and systems and methods including the same
WO2015026367A1 (en) * 2013-08-23 2015-02-26 Halliburton Energy Services, Inc. High-strength, low specific gravity, fracturing balls
US9816339B2 (en) 2013-09-03 2017-11-14 Baker Hughes, A Ge Company, Llc Plug reception assembly and method of reducing restriction in a borehole
US9822615B2 (en) 2013-09-13 2017-11-21 TD Tools, Inc. Apparatus and method for jet perforating and cutting tool
US10174594B2 (en) 2013-09-13 2019-01-08 TD Tools, Inc. Jet perforating and cutting method
WO2015038375A1 (en) * 2013-09-13 2015-03-19 TD Tools, Inc. Apparatus and method for jet perforating and cutting tool
US9910026B2 (en) 2015-01-21 2018-03-06 Baker Hughes, A Ge Company, Llc High temperature tracers for downhole detection of produced water
US10221637B2 (en) 2015-08-11 2019-03-05 Baker Hughes, A Ge Company, Llc Methods of manufacturing dissolvable tools via liquid-solid state molding
US10016810B2 (en) 2015-12-14 2018-07-10 Baker Hughes, A Ge Company, Llc Methods of manufacturing degradable tools using a galvanic carrier and tools manufactured thereof

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