US20060201674A1

US20060201674A1 - Methods of treating subterranean formations using low-temperature fluids

Info

Publication number: US20060201674A1
Application number: US11/076,809
Authority: US
Inventors: Mohamed Soliman; David Adams
Original assignee: Halliburton Energy Services Inc
Current assignee: Halliburton Energy Services Inc
Priority date: 2005-03-10
Filing date: 2005-03-10
Publication date: 2006-09-14

Abstract

Methods for treating subterranean formations using low-temperature fluids are provided. An example of a method is a method of treating a subterranean formation. Another example of a method is a method of fracturing a subterranean formation. Another example of a method is a method of producing hydrocarbons from a subterranean formation.

Description

BACKGROUND

The present invention relates to methods useful in subterranean treatment operations. More particularly, the present invention relates to methods for treating subterranean formations using low-temperature fluids.
Hydrocarbon-bearing subterranean formations penetrated by well bores often may be treated to increase their permeability or conductivity, and thereby facilitate greater hydrocarbon production therefrom. One such production stimulation treatment, known as “fracturing,” involves injecting a treatment fluid (e.g., a “fracturing fluid”) into a subterranean formation or zone at a rate and pressure sufficient to create or enhance at least one fracture therein. Conventional fracturing fluids commonly comprise a proppant material (e.g., sand, or other particulate material) suspended within the fracturing fluid, which proppant material may be deposited into the created fractures. The proppant material functions, inter alia, to prevent the formed fractures from re-closing upon termination of the fracturing operation. Upon placement of the proppant material in the formed fractures, conductive channels may remain within the zone or formation, through which channels produced fluids readily may flow to the well bore upon completion of the fracturing operation.
Because many fracturing fluids suspend proppant material, the viscosity of fracturing fluids often has been increased through inclusion of a viscosifier. After a viscosified fracturing fluid has been pumped into the formation to create or enhance at least one fracture therein, the fracturing fluid generally may be “broken” (e.g., caused to revert into a low viscosity fluid), to facilitate its removal from the formation. The breaking of viscosified fracturing fluids commonly has been accomplished by including a breaker within the fracturing fluid.
The fracturing fluids utilized heretofore predominantly have been water-based liquids containing a viscosifier that comprises a polysaccharide (e.g., guar gum). Guar, and derivatized guar polymers such as hydroxypropylguar, are water-soluble polymers that may be used to create high viscosity in an aqueous fracturing fluid, and that readily may be crosslinked to further increase the viscosity of the fracturing fluid. While the use of gelled and crosslinked polysaccharide-containing fracturing fluids has been successful, such fracturing fluids often have not been thermally stable at temperatures above about 200° F. That is, the viscosity of the highly viscous gelled and crosslinked fluids may decrease over time at high temperatures. To offset the decreased viscosity, the concentration of the viscosifier often may be increased, which may result in, inter alia, increased costs and increased fiction pressure in the tubing through which the fracturing fluid is injected into a subterranean formation. This may increase the difficulty of pumping the fracturing fluids. Thermal stabilizers, such as sodium thiosulfate, often have been included in fracturing fluids, inter alia, to scavenge oxygen and thereby increase the stabilities of fracturing fluids at high temperatures. However, the use of thermal stabilizers also may increase the cost of the fracturing fluids.
Certain types of subterranean formations, such as certain types of shales and coals, may respond unfavorably to fracturing with conventional fracturing fluids. For example, in addition to opening a main, dominant fracture, the fracturing fluid may further invade numerous natural fractures (or “butts” and “cleats,” where the formation comprises coal) that may intersect the main fracture, which may cause conventional viscosifiers within the fracturing fluid to invade intersecting natural fractures. When the natural fractures re-close at the conclusion of the fracturing operation, the conventional viscosifiers may become trapped therein, and may obstruct the flow of hydrocarbons from the natural fractures to the main fracture. Further, even in circumstances where the viscosifier does not become trapped within the natural fractures, a thin coating of gel nevertheless may remain on the surface of the natural fractures after the conclusion of the fracturing operation. This may be problematic, inter alia, where the production of hydrocarbons from the subterranean formation involves processes such as desorption of the hydrocarbon from the surface of the formation. Previous attempts to solve these problems have involved the use of less viscous fracturing fluids, such as non-gelled water. However, this may be problematic, inter alia, because such fluids may prematurely dilate natural fractures perpendicular to the main fracture—a problem often referred to as “near well bore fracture complexity,” or “near well bore tortuosity.” This may be problematic because the creation of multiple fractures, as opposed to one or a few dominant fractures, may result in reduced penetration into the formation, e.g., for a given injection rate, many short fractures may be created rather than one, or a few, lengthy fracture(s). This may be problematic because in low permeability formations, the driving factor to increase hydrocarbon production often is the fracture length. Furthermore, the use of less viscous fracturing fluids also may require excessive fluid volumes, and/or excessive injection pressure. Excessive injection pressure may frustrate attempts to place proppant material into the fracture, thereby reducing the likelihood that the fracturing operation will increase hydrocarbon production.

SUMMARY OF THE INVENTION

The present invention relates to methods useful in subterranean treatment operations. More particularly, the present invention relates to methods for treating subterranean formations using a low-temperature fluid.
An example of a method of the present invention is a method of treating a subterranean formation comprising placing a low-temperature fluid in a subterranean formation so as to create or enhance at least one fracture therein, the low-temperature fluid having a temperature below the ambient temperature at the surface.
Another example of a method of the present invention is a method of fracturing a subterranean formation comprising: positioning a hydrojetting tool having at least one fluid jet forming nozzle in a portion of the subterranean formation to be fractured; and jetting a low-temperature fluid through the nozzle so as to create at least one fracture in the formation, the low-temperature fluid having a temperature below the ambient temperature at the surface.
Another example of a method of the present invention is a method of producing hydrocarbons from a subterranean formation comprising: placing a low-temperature fluid in a subterranean formation so as to create or enhance at least one fracture therein, the low-temperature fluid having a temperature below the ambient temperature at the surface; and permitting hydrocarbons in the formation to flow through the at least one created or enhanced fracture to the surface.
The features and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the description of the preferred embodiments that follows.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete understanding of the present disclosure and advantages thereof may be acquired by referring to the following description taken in conjunction with the accompanying drawings, wherein:
FIG. 1 depicts an embodiment of a tool assembly that may be used with the methods of the present invention.
FIG. 2 is a side cross sectional partial view of a deviated well bore having an embodiment of a tool assembly that may be used with the methods of the present invention therein.
FIG. 3 is a side cross sectional view of the deviated well bore of FIG. 2, after a plurality of microfractures and extended fractures have been created therein in accordance with certain embodiments of the present invention.
FIG. 4 is a cross sectional view taken along line 4-4 of FIG. 2.
While the present invention is susceptible to various modifications and alternative forms, specific embodiments thereof have been shown in the drawings and are herein described. It should be understood, however, that the description herein of specific embodiments is not intended to limit the invention to the particular forms disclosed, but on the contrary, the intention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the invention as defined by the appended claims.

DETAILED DESCRIPTION OF EMBODIMENTS

The present invention relates to methods useful in subterranean treatment operations. More particularly, the present invention relates to methods for treating subterranean formations using a low-temperature fluid. In certain embodiments of the present invention, the use of a low-temperature fluid in the methods and systems of the present invention may result in, among other things, improved “regain permeability” upon the conclusion of the treatment operation. As referred to herein, the term “regain permeability” will be understood to mean the degree to which the permeability of a formation that has been exposed to a treatment fluid approaches the original permeability of the formation. For example, a determination that a subterranean formation evidences “100% regain permeability” at the conclusion of a treatment operation indicates that the permeability of the formation, post-operation, is equal to its permeability before the treatment operation. In certain embodiments of the present invention, the methods and systems of the present invention may permit, inter alia, highly accurate, “pinpoint” placement of a fracture that has been initiated or enhanced through a decrease in temperature at a desired location in a reservoir caused by a low-temperature fluid.
In general, the low-temperature fluids used in the methods and systems of the present invention are fluids that have a temperature below the ambient temperature, the ambient temperature being that which is measured at the surface. Suitable low-temperature fluids should be capable of lowering the temperature of a subterranean formation by a sufficient amount to decrease the amount of hydraulic pressure needed to initiate or enhance a fracture therein. Certain embodiments of suitable low-temperature fluids may be capable of lowering the temperature of the formation sufficient to induce thermal fracturing of the formation. As referred to herein, the terms “thermal fracturing” and “thermally-induced fracture” will be understood to refer to a phenomenon wherein a portion of a subterranean formation fractures upon contact with a low-temperature fluid, the low-temperature fluid being at a pressure below the pressure conventionally required to hydraulically fracture the formation. By way of example and not limitation, it is believed that the low-temperature fluids used in the methods and systems of the present invention may cause instability in the formation with respect to tensile failure, and increased stress intensity at the fracture tip leading to fracture growth. In certain embodiments of the present invention, low-temperature fluids are used that have a temperature in the range of from about (−60)° F. to about 40° F.
In general, the low-temperature fluids used in the methods of the present invention should not damage the formation or be overly invasive. The low-temperature fluids used in the methods of the present invention should not reduce the permeability of the formation, nor should they damage the formation's ability to produce fluid upon the completion of treatment operations involving the low-temperature fluids. Examples of suitable low-temperature fluids that may be used in accordance with the present invention include, but are not limited to, a liquefied gas (e.g., carbon dioxide), and a chilled aqueous solution of potassium chloride. In certain embodiments of the present invention, the chilled aqueous solution of potassium chloride may have a temperature of less than about 40° F. One of ordinary skill in the art, with the benefit of this disclosure, will be able to determine a suitable temperature for the low-temperature fluids with reference to commercially-available well bore simulators. Such simulators may calculate the extent to which the temperature of a fluid may rise as it travels within a well bore; the increase in temperature may be a function of a variety of parameters, including, but not limited to, geothermal gradient, well completion, injection rate, and type of injected fluid. In certain embodiments of the present invention wherein a chilled aqueous solution of potassium chloride is used, a compatibility test may be performed before placement of the chilled aqueous solution of potassium chloride into the subterranean formation; such tests are well within the knowledge of one of ordinary skill in the art, with the benefit of this disclosure.
Certain embodiments of the methods of the present invention involve the use of a low-temperature fluid at a leading edge of a fracturing treatment (e.g., as a “pad” or “pre-pad” fluid). Among other things, this may initiate a thermal fracture in the formation when the formation is exposed to a pressure that may be lower than the pressure at which the formation otherwise would have fractured; this may reduce leak-off of fracturing fluid into the subterranean formation, among other things. Furthermore, in certain embodiments of the present invention, the injection of the low-temperature fluid may be oriented spatially following hydrojetting in the formation. For example, in certain embodiments of the present invention wherein the methods of the present invention are used in treating a horizontal well bore, the injection of the low-temperature fluid may be oriented transverse or longitudinal to the well bore depending on, inter alia, the orientation of the stress field with respect to the well bore. In certain embodiments of the present invention wherein the methods of the present invention are used in treating a deviated well bore, low-temperature fluids may be oriented spatially following hydrojetting in the formation, and the preferred orientation would depend on, inter alia, the stress field, the inclination, and the deviation of the well bore. Among other things, spatially orienting an injected low-temperature fluid following hydrojetting may provide greater control of the orientation in which the resulting fracture is initiated. In certain embodiments of the present invention wherein stress contrast does not exist between two horizontal stresses, the spatial orientation of the injected low-temperature fluid following hydrojetting in the formation also may provide greater control of the resulting fracture's propagation, provided that stress contrast does not exist between two horizontal stresses.
In one embodiment, the present invention provides a system that advantageously may be used with a low-temperature fluid to perform a variety of functions in a subterranean formation. Referring now to FIG. 1, illustrated therein is a hydrojetting tool assembly 150, which in certain embodiments may comprise a tubular hydrojetting tool 140 and a tubular, ball-activated, flow control device 160. The tubular hydrojetting tool 140 generally includes an axial fluid flow passageway 180 extending therethrough and communicating with at least one angularly spaced lateral port 202 disposed through the sides of the tubular hydrojetting tubular hydrojetting tool 140. In certain embodiments, the axial fluid flow passageway 180 communicates with as many angularly spaced lateral ports 202 as may be feasible. A fluid jet forming nozzle 220 generally is connected within each of the lateral ports 202. In certain embodiments, the fluid jet forming nozzles 220 may be disposed in a single plane that may be positioned at a predetermined orientation with respect to the longitudinal axis of the tubular hydrojetting tool 140. Such orientation of the plane of the fluid jet forming nozzles 220 may coincide with the orientation of the plane of maximum principal stress in the formation to be fractured relative to the longitudinal axis of the well bore penetrating the formation.
The tubular, ball-activated, flow control device 160 generally includes a longitudinal flow passageway 260 extending therethrough, and may be threadedly connected to the end of the tubular hydrojetting tool 140 opposite from the coiled or jointed tubing 225. The longitudinal flow passageway 260 may comprise a relatively small diameter longitudinal bore 240 through an exterior end portion of the tubular, ball-activated, flow control device 160 and a larger diameter counter bore 280 through the forward portion of the tubular, ball-activated, flow control device 160, which may form an annular seating surface 290 in the tubular, ball-activated, flow control device 160 for receiving a ball 300. As will be understood by those skilled in the art with the benefit of this disclosure, before ball 300 is seated on the annular seating surface 290 in the tubular, ball-activated, flow control device 160, fluid may freely flow through the tubular hydrojetting tool 140 and the tubular, ball-activated, flow control device 160. After ball 300 is seated on the annular seating surface 290 in the tubular, ball-activated, flow control device 160 as illustrated in FIG. 1, flow through the tubular, ball-activated, flow control device 160 may be terminated, which may cause fluid pumped into the coiled or jointed tubing 225 and into the tubular hydrojetting tool 140 to exit the tubular hydrojetting tool 140 by way of the fluid jet forming nozzles 220 thereof. When an operator desires to reverse-circulate fluids through the tubular, ball-activated, flow control device 160, the tubular hydrojetting tool 140 and the coiled or jointed tubing 225, the fluid pressure exerted within the coiled or jointed tubing 225 may be reduced, whereby higher pressure fluid surrounding the tubular hydrojetting tool 140 and tubular, ball-activated, flow control device 160 may freely flow through the tubular, ball-activated, flow control device 160, causing the ball 300 to disengage from annular seating surface 290, and through the fluid jet forming nozzles 220 into and through the coiled or jointed tubing 225.
Optionally, an operator may elect to employ a pressure sensor (not shown), a temperature sensor (not shown), or a flow meter (not shown) as part of the hydrojetting tool assembly 150. A wide variety of pressure and temperature sensors or flow meters may be used. In certain embodiments, the pressure sensor, temperature sensor, or flow meter may be capable of storing data that may be generated during a subterranean operation until a desired time, e.g., until the completion of the operation when the pressure sensor, temperature sensor, or flow meter is removed from the subterranean function. In certain embodiments of the present invention, the incorporation of a pressure sensor, temperature sensor, or flow meter into the hydrojetting tool assembly 150 may permit an operator to evaluate conditions in the subterranean formation (which conditions may include, but are not limited to, parameters related to the creation or enhancement of the fracture) in real time or near-real-time, and, inter alia, to undertake a remediative step in real time or near-real-time. Example of remediative steps include, inter alia, switching from a low-temperature fluid to a conventional fracturing fluid, increasing the rate of fluid injection, adding proppant to the fluid being injected, and the like. In certain embodiments of the present invention, the operator may be able to determine, in real-time, that the fracture in the subterranean formation has been created or enhanced to a desired extent. In certain embodiments, the operator may move hydrojetting tool assembly 150 to a different zone in the same, or different, formation after determining, in real time, that the fracture has been created or enhanced to a desired extent. As referred to herein, the term “real time” will be understood to mean a time frame in which the occurrence of an event and the reporting or analysis of it are almost simultaneous; e.g., within a maximum duration of not more than two periods of a particular signal (e.g., a pressure signal, electrical signal, or the like) being evaluated. For example, an operator may view, in real time, a plot of the pressure in the formation that has been transmitted by the optional pressure sensor (not shown), and determine, at a particular time during the fracturing operation, that an increase, or multiple increases, in the slope of the pressure indicate the need to perform a remediative step such as those described above. One of ordinary skill in the art, with the benefit of this disclosure, will be able to evaluate a real time plot of the pressure in the formation, and evaluate conditions in the formation, and determine the appropriate remediative step to perform in response. For example, an operator may use the flow meter, in real time, to compare the flow of fluid past the end of the hydrojetting tool assembly 150 to determine the quantity of fluid that is flowing into the at least one fracture in the subterranean formation, and to determine the quantity of fluid that is flowing past the hydrojetting tool assembly 150 and that may be leaking off into other areas; the operator may evaluate such data from the flow meter, and adjust the fluid flow rate and jetting pressure accordingly. One of ordinary skill in the art, with the benefit of this disclosure, will be able to evaluate data from the flow meter, and determine the appropriate adjustments to make to the fluid flow rate and jetting pressure.
Referring now to FIG. 2, a hydrocarbon-producing subterranean formation 400 is illustrated penetrated by a deviated open hole well bore 420. The deviated well bore 420 includes a substantially vertical portion 440 which extends to the surface, and a substantially horizontal portion 460 which extends into the formation 400. Though FIG. 2 illustrates an open hole well bore, it will be understood that the methods of the present invention also may be used in well bores having casing disposed therein; it further will be understood that the methods of the present invention also may be used in a variety of well bore configurations, including, but not limited to, those that are entirely vertical and those that are substantially vertical.
The coiled or jointed tubing 225 having the hydrojetting tool assembly 150, and an optional centralizer 480, attached thereto is shown disposed in the well bore 420. Prior to placing the hydrojetting tool assembly 150, the optional centralizer 480 and the coiled or jointed tubing 225 into the well bore 420, an operator may determine the orientation of the plane of maximum principal stress in the formation 400 to be fractured with respect to the longitudinal direction of the well bore 420 utilizing known information or techniques and tools available to those of ordinary skill in the art. Thereafter, the tubular hydrojetting tool 140 may be selected having the fluid jet forming nozzles 220 disposed in a plane oriented with respect to the longitudinal axis of the tubular hydrojetting tool 140 in a manner that aligns the plane containing the fluid jet forming nozzles 220 with the plane of the maximum principal stress in the formation 400 when the tubular hydrojetting tool 140 is positioned in the well bore 420. As is well understood in the art, when the fluid jet forming nozzles 220 are aligned in the plane of the maximum principal stress in the formation 400 to be fractured and a fracture is formed therein, a single microfracture may be formed that may extend outwardly from and around the well bore 420 in the plane of maximum principal stress. In certain embodiments of the present invention, an operator may elect not to align the fluid jet forming nozzles 220 of the tubular hydrojetting tool 140 with the plane of maximum principal stress in the formation 400; in such embodiments, each fluid jet may form an individual cavity and fracture in the formation 400.
Once the hydrojetting tool assembly 150 has been placed in the well bore 420, a low-temperature fluid, such as those that have been described herein, may be circulated through the coiled or jointed tubing 225 and through the hydrojetting tool assembly 150 so as to flow through the open tubular, ball-activated, flow control device 160 and circulate through the well bore 420. In certain embodiments, the circulation may be continued for a period of time sufficient to clean out debris, pipe dope and other materials from inside the coiled or jointed tubing 225 and from the well bore 420. Once a desired volume of low-temperature fluid has been placed in well bore 420, and hydrojetting tool assembly 150 has been positioned adjacent the formation 400 that is to be fractured, ball 300 (shown in FIG. 1) may be caused to seat on the annular seating surface 290 (shown in FIG. 1) in the tubular, ball-activated, flow control device 160, thereby directing the entirety of the low-temperature fluid through the fluid jet forming nozzles 220 of the tubular hydrojetting tool 140. In certain embodiments, ball 300 may be caused to seat on annular seating surface 290 by dropping ball 300 through coiled or jointed 225, through the tubular hydrojetting tool 140 and into the tubular, ball-activated, flow control device 160 while the low-temperature fluid continues to flow through the coiled or jointed tubing 225 and the hydrojetting tool assembly 150; in certain other embodiments, ball 300 may be trapped in the tubular hydrojetting tool 140, and will seat when fluid flows through coiled or jointed tubing 225, forcing fluid out the fluid jet forming nozzles 220.
After ball 300 has been caused to seat on annular seating surface 290, the rate of circulation of the low-temperature fluid into the coiled or jointed tubing 225 and through the tubular hydrojetting tool 140 may be increased to a level whereby the pressure of the low-temperature fluid that is jetted through the fluid jet forming nozzles 220 may reach a jetting pressure sufficient to perforate the walls of well bore 420 and cause the creation of cavities 500 and microfractures 520 in the subterranean formation 400 as illustrated in FIGS. 2 and 4.
Once a cavity 500 is formed, the operator may, inter alia, close in the annulus, which may increase the pressure and thereby assist in creating a dominant fracture adjacent the tubular hydrojetting tool 140. Fluid (which may be a low-temperature fluid) may be flowed through the annulus to increase the flow rate of fluid into the fracture, thereby assisting in propagating the fracture. Flowing fluid through the annulus also may assist in overcoming any leak-off of fluid into other perforations that may occur.
Generally, the jet differential pressure at which the low-temperature fluid is jetted from the fluid jet forming nozzles 220 of the tubular hydrojetting tool 140 to result in the formation of cavities 500 and microfractures 520 in the formation 400 is a pressure in the range of from about 500 to about 5,000 psi. In certain embodiments, the jet differential pressure at which the low-temperature fluid is jetted from the fluid jet forming nozzles 220 of the tubular hydrojetting tool 140 is a pressure of approximately two times the pressure required to initiate a fracture in the formation, less the ambient pressure in the well bore adjacent to the formation. In certain embodiments of the present invention, a lesser jetting pressure may be required, as contact between the low-temperature fluid and the rock in the formation may thermally induce a fracture in the formation at a lower pressure than would be required when using a conventional ambient-temperature fracturing fluid. In certain embodiments of the present invention, the low-temperature fluid may be injected into the formation at a pressure less than the conventional fracture propagation and/or initiation pressure, and the orientation of the fracture then may be controlled by local heterogeneity (e.g., permeability and thermal properties). As referred to herein, the term “conventional fracture propagation and/or initiation pressure” will be understood to mean the pressure at which a fracture within the formation would be initiated and/or propagate by conventional fracturing operations that do not involve the injection of a low-temperature fluid into the formation. In certain embodiments of the present invention, the low-temperature fluid may be injected into the formation at a pressure above the conventional fracture propagation and/or initiation pressure, in which case a hydraulic fracture would propagate; the hydraulic fracture may propagate at a significantly lower pressure than would be required with a conventional ambient-temperature fluid. The pressure required to initiate a fracture in a particular formation may depend upon, inter alia, the particular type of rock and/or other materials that form the formation (including, but not limited to, the physical, mechanical, and thermal properties of the rock), the temperature of the low-temperature fluid, and other factors known to those skilled in the art.
Once one or more dominant fractures have been created, a valve on the annulus may be opened, and fluid flow into the annulus may be initiated so as to further enhance or extend the one or more dominant fractures. Among other things, flowing a low-temperature fluid through the annulus, as well as through coiled or jointed tubing 225, may provide the largest possible flow path for the low-temperature fluid, thereby increasing the rate at which the low-temperature fluid may be forced into formation 400. Among other things, flowing the low-temperature fluid through both the annulus and through coiled or jointed tubing 225 may reduce erosion of fluid jet forming nozzles 220 when the low-temperature fluid is proppant-laden.
In certain embodiments of the present invention, the fluid that is hydrojetted to create perforation tunnels in the formation may be a fluid other than a low-temperature fluid, and a low-temperature fluid may be utilized once the perforation tunnels have been created. For example, in certain embodiments of the present invention, the fluid that is hydrojetted may be an abrasive fluid of about ambient temperature, and, at a desired time after the creation of the perforation tunnels (or contemporaneously with the creation of the perforation tunnels) a low-temperature fluid may be placed within the formation to create or enhance at least one fracture therein.
In certain embodiments of the present invention, a low-temperature fluid may be flowed into the subterranean formation through an insulated coiled tubing, inter alia, to prevent or reduce heat transfer while the low-temperature fluid is flowing towards the formation to be fractured.
Once one or more dominant fractures in formation 400 have been created and then extended or enhanced to a desired extent, hydrojetting tool assembly 150 may be moved within well bore 420 to other zones in the same, or different, formation and the process described above may be repeated so as to create perforations in the walls of well bore 420 adjacent such other zones, and to create or enhance dominant fractures in such other zones, as previously described herein.
When the well bore 420 is deviated (including horizontal well bores) as illustrated in FIG. 2, the optional centralizer 480 may be utilized with the hydrojetting tool assembly 150, inter alia, to insure that each of the fluid jet forming nozzles 220 has a proper stand-off clearance from the walls of the well bore 420, (e.g., a stand-off clearance in the range of from about ¼ inch to about 2 inches). At a stand-off clearance of about 1.5 inches between the face of the fluid jet forming nozzles 220 and the walls of the well bore and when the fluid jets formed flare outwardly at their cores at an angle of about 20 degrees, the jet differential pressure required to form the cavities 500 and the microfractures 520 generally is a pressure of about 2 times the pressure required to initiate a fracture in the formation less the ambient pressure in the well bore adjacent to the formation. When the stand-off clearance and degree of flare of the fluid jets are different from those given above, an operator may use formulae such as the following to determine a desirable jetting pressure:
Pi=Pf−Ph FORMULA I
ΔP/Pi=1.1[d+(s+0.5)tan(flare)]² /d ² FORMULA II
wherein;
Pi=difference between formation fracture pressure and ambient pressure (psi);
Pf=formation fracture pressure (psi);
Ph=ambient pressure (psi);
ΔP=the jet differential pressure (psi);
d=diameter of the jet (inches);
s=stand off clearance (inches); and
flare=flaring angle of jet (degrees).
In certain embodiments of the present invention, an optional proppant particulate may be combined with the low-temperature fluid being circulated so that it is carried into cavities 500, as well as at least partially into microfractures 520 connected to cavities 500. However, the use of a proppant particulate is not required with the present invention, because, inter alia, fractures formed using a low-temperature fluid may be self propped, inter alia, due to formation material failure at the fracture face. At least initially, fracture face failure may occur along lines of heterogeneity and/or lithological weakness, which may expose new areas of the formation (at about the original formation temperature prior to commencement of the fracturing operation) to the low-temperature fluid. The failed formation material may prop the fracture open in a manner akin to that of a proppant particulate.
In certain optional embodiments of the present invention wherein a proppant particulate may be included with the low-temperature fluids being circulated, the proppant particulate functions, inter alia, to prop open microfractures 520 and thereby prevent them from completely re-closing upon termination of the hydrojetting process. In order to insure that proppant particulate remains in the fractures upon termination of the hydrojetting process, the jetting pressure preferably may be slowly reduced to allow the fractures to close upon the proppant particulate that is held within the fractures by the fluid jetting during the closure process. In addition to propping the fractures open, the presence of the proppant particulate, (e.g., sand) in the fluid being jetted facilitates the cutting and erosion of the formation by the fluid jets. Once one or more microfractures are formed as a result of the above procedure, the hydrojetting tool assembly 150 may be moved to a different position, and the hydrojetting procedure may be repeated to form one or more additional microfractures that may be spaced a distance from the initial microfracture or microfractures.
As mentioned above, some or all of the microfractures produced in a subterranean formation may be extended into the formation by pumping a low-temperature fluid into the well bore to raise the ambient pressure therein. In performing the methods of the present invention to initiate and extend at least one fracture in the subterranean formation, the hydrojetting tool assembly 150 may be positioned in the well bore 420 adjacent the formation 400 to be fractured, and fluid may be jetted through the fluid jet forming nozzles 220 against the formation 400 at a jetting pressure sufficient to form the cavities 500 and the microfractures 520. Simultaneously with the hydrojetting of the formation, a fluid (e.g., a low-temperature fluid, or an ambient-temperature fluid, such as an ambient-temperature aqueous potassium chloride solution) may be pumped into the well bore 420 at a rate sufficient to raise the ambient pressure in the well bore adjacent the formation to a level such that the cavities 500 and the microfractures 520 are enlarged and extended, whereby enlarged and extended fractures 600 (shown in FIG. 3) are formed. As in an embodiment that is illustrated in FIG. 3, the enlarged and extended fractures 600 may be formed in a spaced relationship along well bore 420 with groups of the cavities 500 and microfractures 520 formed therebetween.
To facilitate a better understanding of the present invention, the following examples of certain embodiments are given. In no way should such examples be read to limit, or to define, the scope of the invention.

EXAMPLES

A hypothetical example may further illustrate certain aspects of the present invention. This example assumes perfect heat transfer from the low-temperature fluid to the formation. The following definitions are pertinent to this example:

- C_pCompressibility of the formation to be fractured
- C_tCoefficient of thermal expansion of the formation to be fractured
- V Volume of formation over which the temperature was reduced
- T_fOriginal formation temperature before the treatment operation
- ΔV Change in formation volume V during the treatment operation
- ΔP Change in pressure due to change in volume of the formation during the treatment operation
- ΔT_fChange in formation temperature due to contact between the formation volume V and the low-temperature fluid during the treatment operation
- T_ciThermal capacitance of low-temperature-fluid
- T_cfThermal capacitance of formation
- Φ Porosity of formation
- T_iTemperature of injected fluid
- T_sTemperature at which the formation and the fluid equilibrate

The following equations generally may be used, inter alia, to calculate the appropriate temperature T_iof the low-temperature-fluid to cause ΔP to exceed C_p.
C _p=[1/v]*[ΔV/ΔP] EQUATION 1
C _t=[1/v]*[ΔV/ΔT _f] EQUATION 2
When EQUATION 1 is set equal to EQUATION 2, the result is EQUATION 3, set forth below:
ΔP=[C _t /C _p ]*ΔT _f EQUATION 3
EQUATIONS 4 and 5 may be introduced . . .
ΔT _f =T _f −T _s EQUATION 4
T _ci*Φ*(T _s −T _i)=T _cf*(1−Φ)*(T _f −T _s) EQUATION 5
For example, if the equations above are used in a hypothetical example wherein typical reservoir thermal properties and physical properties are assumed, and wherein a conservative reduction in formation temperature of 200° F. is assumed, EQUATION 3 may reduce to the following: ΔP=[7.2e⁻⁶/3.0e⁻⁶]*200=480 psi. This hypothetical example suggests that the pressure required to fracture the formation under such circumstances would be reduced by 480 psi.
Alternatively, the equations above could be used to determine, for a particular chosen T_i, the corresponding reduction in the pressure necessary to initiate a fracture in the formation from the pressure conventionally required when conventional fracturing fluids are used.
Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. While the invention has been depicted and described by reference to particular 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. 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.

Claims

1. A method of treating a subterranean formation comprising placing a low-temperature fluid in a subterranean formation so as to create or enhance at least one fracture therein, the low-temperature fluid having a temperature below the ambient temperature at the surface.

2. The method of claim 1 wherein the low-temperature fluid has a temperature of less than about 40° F.

3. The method of claim 1 wherein the low-temperature fluid comprises a liquefied gas.

4. The method of claim 1 wherein the low-temperature fluid comprises an aqueous solution of potassium chloride having a temperature of about, or below, 40° F.

5. The method of claim 3 wherein the liquefied gas comprises carbon dioxide.

6. The method of claim 1 wherein the at least one created or enhanced fracture is a thermally-induced fracture.

7. A method of fracturing a subterranean formation comprising:

positioning a hydrojetting tool having at least one fluid jet forming nozzle in a portion of the subterranean formation to be fractured; and

jetting a low-temperature fluid through the nozzle so as to create at least one fracture in the formation, the low-temperature fluid having a temperature below the ambient temperature at the surface.

8. The method of claim 7 wherein the low-temperature fluid comprises a liquefied gas.

9. The method of claim 7 wherein the low-temperature fluid comprises an aqueous solution of potassium chloride having a temperature of about, or below, 40° F.

10. The method of claim 8 wherein the liquefied gas comprises carbon dioxide.

11. The method of claim 7 wherein jetting a low-temperature fluid through the nozzle so as to create at least one fracture therein further comprises inducing the formation to thermally fracture.

12. The method of claim 7 further comprising flowing the low-temperature fluid from ground surface to the hydrojetting tool, wherein the low-temperature fluid flows through at least one insulated conduit section.

13. The method of claim 7 further comprising flowing the low-temperature fluid from ground surface to the hydrojetting tool, wherein the low-temperature fluid flows through insulated coiled tubing.

14. The method of claim 7 wherein the low-temperature fluid has a temperature of less than about 40° F.

15. The method of claim 7 further comprising pumping a low-temperature fluid into an annulus between the hydrojetting tool and the formation so as to extend the at least one fracture into the formation.

16. A method of producing hydrocarbons from a subterranean formation comprising:

placing a low-temperature fluid in a subterranean formation so as to create or enhance at least one fracture therein, the low-temperature fluid having a temperature below the ambient temperature at the surface; and

permitting hydrocarbons in the formation to flow through the at least one created or enhanced fracture to the surface.

17. The method of claim 16 wherein the low-temperature fluid has a temperature of less than about 40° F.

18. The method of claim 16 wherein the low-temperature fluid comprises a liquefied gas.

19. The method of claim 16 wherein the low-temperature fluid comprises an aqueous solution of potassium chloride having a temperature of about, or below, 40° F.

20. The method of claim 16 wherein the at least one created or enhanced fracture is a thermally-induced fracture.