CA2644213C - Method of treating subterranean formations using mixed density proppants or sequential proppant stages - Google Patents

Method of treating subterranean formations using mixed density proppants or sequential proppant stages Download PDF

Info

Publication number
CA2644213C
CA2644213C CA2644213A CA2644213A CA2644213C CA 2644213 C CA2644213 C CA 2644213C CA 2644213 A CA2644213 A CA 2644213A CA 2644213 A CA2644213 A CA 2644213A CA 2644213 C CA2644213 C CA 2644213C
Authority
CA
Canada
Prior art keywords
proppant
stage
ulw
proppant stage
fracture
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Expired - Lifetime
Application number
CA2644213A
Other languages
French (fr)
Other versions
CA2644213A1 (en
Inventor
Harold Dean Brannon
William Dale Wood
Randall Edgeman
Allan Ray Rickards
Christopher John Stephenson
Doug Walser
Mark Malone
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Baker Hughes Holdings LLC
Original Assignee
Baker Hughes Inc
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Baker Hughes Inc filed Critical Baker Hughes Inc
Priority to CA2795417A priority Critical patent/CA2795417C/en
Publication of CA2644213A1 publication Critical patent/CA2644213A1/en
Application granted granted Critical
Publication of CA2644213C publication Critical patent/CA2644213C/en
Anticipated expiration legal-status Critical
Expired - Lifetime legal-status Critical Current

Links

Classifications

    • CCHEMISTRY; METALLURGY
    • C09DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09KMATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60Compositions for stimulating production by acting on the underground formation
    • C09K8/62Compositions for forming crevices or fractures
    • CCHEMISTRY; METALLURGY
    • C09DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09KMATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60Compositions for stimulating production by acting on the underground formation
    • C09K8/80Compositions for reinforcing fractures, e.g. compositions of proppants used to keep the fractures open
    • 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
    • YGENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y10TECHNICAL SUBJECTS COVERED BY FORMER USPC
    • Y10STECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y10S507/00Earth boring, well treating, and oil field chemistry
    • Y10S507/922Fracture fluid
    • Y10S507/924Fracture fluid with specified propping feature

Abstract

An increase in effective propped lengths is evidenced in hydraulic fracturing treatments by the use of ultra lightweight (ULW) proppants. The ULW proppants have a density less than or equal to 2.45 g/cc and may be used as a mixture in a first proppant stage wherein at least one of the proppants is a ULW proppant. Alternatively, sequential proppant stages may be introduced into the formation wherein at least one of the proppant stages contain a ULW proppant and where at least one of the following conditions prevails: (i.) the density differential between the first proppant stage and the second proppant stage is greater than or equal to 0.2 g/cc; (ii.) both the first proppant stage and the second proppant stage contain a ULW proppant; (iii.) the rate of injection of the second proppant stage into the fracture is different from the rate of injection of the first proppant stage; or (iv.) the particle size of the second proppant stage is different form the particle size of the first proppant.

Description

=
APPLICATION FOR PATENT
INVENTORS: HAROLD DEAN BRANNON; WILLIAM DALE WOOD;
RANDALL EDGEMAN; ALLAN RAY RICKARDS;
CHRISTOPHER JOHN STEPHENSON; DOUG WALSER. AND
MARK MALONE
TITLE: METHOD OF TREATING SUBTERRANEAN FORMATIONS
USING MIXED DENSITY PROPPANTS OR SEQUENTIAL
PROPPANT STAGES
SPECIFICATION
Field of the Invention This invention relates to a method of treating subterranean formations and, more specifically, to hydraulic fracturing treatments for subterranean formations.
Use of the .
method of the invention renders an increase in effective propped lengths by as much as 100%. Thus, the inventive method increases well productivity, greatly enhances reservoir drainage, and improves hydrocarbon recovery.
Background of the Invention Hydraulic fracturing is a common stimulation technique used to enhance production of fluids from subterranean formations. Hydraulic fracturing is typically employed to stimulate wells which produce from low permeability formations. In such wells, recovery efficiency is typically limited by the flow mechanisms associated with a low permeability formation.
During hydraulic fracturing, a viscosified fracturing fluid is pumped at high pressures and at high rates into a wellbore to initiate and propagate a hydraulic fracture.
Once the natural reservoir pressures are exceeded, the fluid induces a fracture in the formation and transports the proppant into the fracture. The fluid used to initiate and propagate the fracture is commonly known as the "pad". The pad may contain a heavy density fine particulate, such as fine mesh sand, for fluid loss control, or larger grain sand to abrade perforations or near-wellbore tortuosity. Once the fracture is initiated, subsequent stages of viscosifled fracturing fluid containing chemical agents such as breakers, and containing proppants are pumped into the created fracture. The fracture generally continues to grow during pumping and the proppant remains in the fracture in the form of a permeable "pack" that serves to "prop" the fracture open. Once the treatment is completed, the fracture closes onto the proppants which maintain the fracture open, providing a highly conductive pathway for hydrocarbons and/or other formation fluids to flow into the wellbore. The fracturing fluid ultimately "leaks off' into the surrounding formation. The treatment design generally requires the fracturing fluid to reach maximum viscosity as it enters the fracture which affects the fracture length and width.
Fracturing fluids, including those containing breakers, typically exhibit poor transport properties. High pumping rates are required in order to impart a sufficient velocity for placement of the proppant in the fracture. In such treatments, the proppant tends to settle, forming a 'proppant bank', as the linear slurry velocity falls as a function of the distance from the wellbore. This effect is further believed to result in reduced stimulation efficiency as the effective propped length is relatively short. In addition, much of the settled proppant is often below the productive interval.
The recovery of the fracturing fluid is accomplished by reducing the viscosity of the fluid to a low value such that it flows naturally from the formation under the influence of formation fluids and pressure. This viscosity reduction or conversion is referred to as "breaking". Historically, the application of breaking fluids as fracturing fluids at elevated temperatures, i.e., above about 120-130 F., has been a compromise between maintaining proppant transport and achieving the desired fracture conductivity, measured in terms of effective propped fracture length. Conventional oxidative breakers react rapidly at elevated temperatures, potentially leading to catastrophic loss of proppant transport.
Encapsulated oxidative breakers have experienced limited utility at elevated temperatures due to a tendency to release prematurely or to have been rendered ineffective through payload self-degradation prior to release.
Improvements in hydraulic fracturing techniques are required in order to increase the effective propped fracture length and thereby improve stimulation efficiency and well productivity.
Summary of the Invention The invention relates to a method of hydraulically fracturing a hydrocarbon-bearing subterranean formation by introducing into the formation one or more proppant stages wherein at least one of the proppant stages contains an ultra lightweight (ULW) proppant having a density less than or equal to 2.45 Wee. The method results in an increase in the effective propped fracture length. The first proppant stage may consist of a mixture of proppants, at least one of which is an ULW proppant having a density less than or equal to 2.45 g/cc. Alternatively, sequential proppant stages may be introduced into the formation wherein at least one of the proppant stages contains a ULW
proppant.
The first proppant stage may be a pad fluid, containing a proppant, and pumped at a pressure sufficient to initiate a fracture. Alternatively, the first proppant stage may be pumped into a propagated fracture. As such, the first proppant stage of the invention may be introduced into the fracture subsequent to propagation of the fracture. An optional second proppant stage may be injected into the fracture after introduction of the first proppant stage. Successive proppant stages may be injected into the fracture after injection of the optional second proppant stage. The second proppant stage may be introduced into the formation immediately after the first proppant stage.
Thus, in the method of the invention, at least one of the following conditions should prevail:
(i.) the first proppant stage contains a mixture of proppants ¨ for example, a first proppant and a second proppant - wherein at least one of the proppants is a ULW;
preferably, the density differential between the ULW proppant and the second proppant in the proppant mixture is greater than or equal to 0.2 ?ice. For instance, the first proppant stage may contain a mixture of two proppants comprising a ULW
proppant and a non-ULW proppant. In such proppant mixtures, the differential in the density between the two proppants is preferably greater than 0.2 g/cc. Alternatively, where the invention encompasses two or more proppant stages, all or some of the proppant stages may contain a mixture of proppants, wherein within each proppant stage, at least one of the proppants is a ULW proppant. In each proppant stage, the density of the ULW
proppant within the mixture is preferably greater than or equal to 0.2 g/cc the density of a second proppant within the mixture;
(ii.) the density differential between the first proppant stage and the second proppant stage is greater than or equal to 0.2 glee;
(iii.) the first proppant stage and the second proppant stage both contain ULW

proppants;
(iv.) the proppant of the first proppant stage and/or the second proppant stage is a ULW and the rate of injection of the second proppant stage into the fracture is different from the rate of injection of the first proppant stage; in a preferred mode, the rate of injection of the second proppant stage is less than the rate of injection of the first proppant stage; or (v.) the proppant of the first proppant stage and/or the second proppant stage contains a ULW proppant and the particle size of the second proppant stage is different from the particle size of the first proppant stage; in a preferred mode, the particle size of the second proppant stage is preferably larger than the particle size of the proppant of the first proppant stage when the second proppant stage is directed more towards the wellbore. The particle size of the second proppant stage is preferably smaller than the particle size of the proppant of the first proppant stage when the second proppant stage is directed further into the fracture.
The effective propped length of the fracture after injection of any given proppant stage is preferably greater than the effective propped length of the proppant stage introduced into the fracture just prior to the injection of the any given proppant stage.
In a preferred embodiment, the first proppant stage comprises a first proppant and a second proppant, wherein the first proppant is a relatively high-density proppant, i.e., having a density greater than 2.45 glee, such as sand, ceramic, sintered bauxite or resin coated proppant, and the second proppant is a ULW proppant. A subsequent second proppant stage may include an ultra-lightweight proppant, exhibiting a particle density substantially lower than the density of the relatively high-density proppant.
For instance, the proppant of the subsequent proppant stage has a density less than or equal to 2.45 glee, preferably ranging between from about 1.25 g/cc to about 1.75 glee.
Additional proppant stages may be introduced into the formation after introduction of the second proppant stage. Such additional proppant stages will be referred to herein as the "ultimate proppant stage" and the "penultimate proppant stage"
to refer to the latter and next to latter proppant stages, respectively. For example, where three proppant stages are employed and when referring to the third and second proppant stages, the third proppant stage may be referred to as the "ultimate proppant stage" and the second proppant stage as the "penultimate proppant stage." Where four proppant stages are employed and when referring to the fourth and third proppant stages, the fourth proppant stage may be referred to as the "ultimate proppant stage" and the third proppant stage may be referred to as the "penultimate proppant stage," etc. The ultimate proppant stage may be introduced into the formation immediately after the penultimate proppant stage. At least one of the following conditions preferably prevails:
(i.) the density differential between the ultimate proppant stage and the penultimate proppant stage is greater than or equal to 0.2 g/cc; for instance, when referring to the third and second proppant stages, the density differential between the third proppant stage and the second stage is greater than or equal to 0.2 g/cc;
(ii.) the rate of injection of the ultimate proppant stage into the fracture is different from the rate of injection of the penultimate proppant stage;
typically, the rate of injection of the ultimate proppant stage into the fracture is lower than the rate of injection of the penultimate proppant stage into the fracture; or (iii.) the particle size of the ultimate proppant stage is different from the particle size of the penultimate proppant stage; typically, the particle size of the proppant of the ultimate proppant stage into the fracture is dependent on whether the proppant stage is directed more towards the wellbore (generally larger) or further into the fracture (generally smaller).
In a preferred embodiment, the first proppant stage comprises a first proppant and a second proppant, wherein the first proppant is a relatively high-density proppant, such as sand, ceramic, sintered bauxite or resin coated proppant, and the second proppant has a density less than or equal to 2.45 Wee.
=
Alternatively, a fracture may be created in the formation by injecting a banking fluid containing a first proppant stage into the formation at a pressure sufficient to allow the formation of a proppant bank. A second proppant stage is then injected into the fracture. The proppant of either the first proppant stage or the second proppant stage or both may contain a ULW proppant. In a preferred embodiment, the density differential between the proppant of the first proppant stage (the banking fluid) and the proppant of the second proppant stage is at least 0.2 glee.
Alternatively, a fluid containing a relatively high-density proppant may be used to propagate the fracture, allowing it to form the bank. The subsequent second proppant stage may include an ultra-lightweight proppant, exhibiting a particle density substantially lower than the density of the relatively high-density proppant.
For instance, the proppant of the subsequent proppant stage may have a density ranging between from about 1.25 g/cc to about 1.75 g/cc.
The invention further has particular applicability in the use of a ULW
proppant in a pad fluid to initiate a fracture in the formation. The second proppant stage introduced into the fracture may contain a ULW proppant or a proppant of higher density, such as, for example, sand, ceramic, bauxite, or resin coated proppant. The density differential between the first proppant stage, or pad fluid, and second proppant stage is preferably at least 0.2 glee.
The method of incorporating two or more proppant stages under the defined conditions, or using two or more mixed proppants in a single proppant stage, having a ULW proppant provides significant benefits relative to treatments with conventional high-density proppants. In addition, the method provides significant benefits as compared to prior art methods. Such benefits include a reduction in costs and the potential for significantly improved effective propped fracture length.
Brief Description of the Drawings FIG. 1 is a 2D depiction of a fracture, after closure of the fracture, initiated with a fluid pad not containing a ULW proppant, the fracture being successively treated, with a second proppant stage.
FIG. 2 is a 2D depiction of a fracture, after closure of the fracture, initiated with a fluid pad containing a ULW proppant, the fracture being successively treated with a second proppant stage.
Detailed Description of the Preferred Embodiments The method of fracturing a hydrocarbon-bearing subterranean formation, as defined by the invention, provides greater effective propped fracture length than seen with conventional fracturing techniques. Effective propped fracture lengths may be increased by as much as 100%. Such greater effective propped fracture length translates to improved stimulation efficiency, well productivity and reservoir drainage.
While not intending to be bound by any theory, it is believed that the enhanced effective length of the propped fracture is attributable to the reduced cross-sectional flow area existing above the settled bank. Where the first proppant stage is used to propagate the fracture, it is believed that the reduced cross-sectional flow area exists above the settled bank generated by this first proppant stage. Assuming constant pumping rates at the wellbore, the reduced cross-sectional area "artificially" increases the velocity of the second or successive proppant stages through that section of the fracture, leading to improved transport and deeper placement of the second or successive proppant stages into the fracture than would be achieved within the created fracture in the absence of the proppant bank.
In a preferred embodiment, the method of the invention consists of fracturing by introducing into the formation the use of multiple proppant stages wherein at least one of the proppant stages contains a ULW density proppant. Alternatively, the method consists of using a single proppant stage containing at least two proppants, wherein at least one of the proppant stages contains a ULW density proppant. As defined herein, a ULW
proppant is one which has a density less than or equal to 2.45 g/cc.
The formation may first be propagated by introducing into the formation a proppant stage at a pressure sufficient to propagate the fracture. This proppant stage, which initiates the fracture, typically contains a conventional high-density proppant, though it may contain, in addition to or in lieu of the conventional high-density proppant, a ULW proppant.
The "first proppant stage" of the invention may refer to either the proppant stage introduced into the formation to propagate the fracture or a proppant stage introduced into the formation after propagation has occurred. Thus, the term "first proppant stage" is not to be construed as encompassing only the first proppant stage introduced to the The "first proppant stage" may contain a mixture of proppants, at least one of which is a ULW proppant. In a preferred mode, the first proppant stage contains at least two proppants. In a more preferred mode, the density differential of the two proppants in If the first proppant stage contains either a single proppant (either conventional high-density or ULW proppant) or a mixture of proppants, none of which are a ULW
proppant, it is typically necessary to introduce a subsequent proppant stage into the Where a second proppant stage is employed, it is preferred that at least one of the following conditions should further prevail:
(i.) the first proppant stage and/or second proppant stage contains a mixture of proppants, at least one of which is a ULW proppant and, preferably wherein the density (ii.) the first proppant stage and/or the second proppant stage contains a ULW

proppant and the density differential between the first proppant stage and the second proppant stage is greater than or equal to 0.2 glee, preferably greater than or equal to 0.50 glee, most preferably greater than or equal to 0.80 g/cc. Preferably, the density of the second proppant stage is less than the density of the first proppant stage.
For instance, the density of the proppant of the first proppant stage may be around 2.65 and the density of the proppant of the second proppant stage may be 1.90;
(iii.) both the first proppant stage and the second proppant stage contain ULW

proppants;
(iv.) the proppant of the first proppant stage and/or the second proppant stage contain a ULW proppant and the rate of injection of the second proppant stage into the fracture is different from the rate of injection of the first proppant stage.
Typically, the rate of injection of the second proppant stage is lower than the rate of injection of the first proppant stage. Typically the rate of injection of each of the proppant stages is greater than or equal to 5 barrels per minute. The rate of injection of any given proppant stage may be as high as 250 barrels/minute; or (v.) the proppant of the first proppant stage and/or second proppant stage contain a ULW proppant and the particle size of the second proppant stage is different from the particle size of the first proppant stage; typically, the particle size of the proppant of the second proppant stage is greater than the particle size of the proppant of the first proppant stage, especially where the second proppant stage is directed more towards the wellbore and smaller than the particle size of the proppant of the first proppant stage especially where the second proppant stage is directed further into the fracture. Typically, the particle size of the proppant with the proppant system used in the invention is from about 8/12 US mesh to about 100 US mesh. Most typically, the particle size of the proppant with the proppant system used in the invention is from about 12/20 US mesh to about 40/70 US mesh.
Successive proppant stages may be injected into the fracture after injection of the second proppant stage. Thus, the invention may consist of multiple proppant introductions provided at least one of the following conditions prevail:
(i.) the differential in density between the ultimate (successive) proppant stage and the penultimate proppant stage is greater than or equal to 0.2 g/cc;
(ii.) the rate of injection of the ultimate proppant stage into the fracture is different from the rate of injection of the penultimate proppant stage;
typically, the rate of injection of the ultimate proppant stage into the fracture is lower than the rate of injection of the penultimate proppant stage into the fracture; or (iii.) the particle size of the ultimate Koppant stage is different from the particle size of the penultimate proppant stage.
The limitation to the number of stages employed is principally based upon practicality from an operational perspective.
The effective propped length of the fracture after injection of the ultimate proppant stage is preferably greater than the effective propped length of the penultimate proppant stage.
In a preferred embodiment, the first proppant stage comprises a mixture of a first proppant and a second proppant, wherein the first proppant is a conventional high-density proppant, such as sand, ceramic, sintered bauxite or resin coated proppant, and the second proppant is a ULW proppant having a density less than or equal to 2.45 g/cc.
In another preferred embodiment, the process of the invention requires at least two proppant stages wherein the density differential between the first proppant stage and the second proppant stage is at least 0.2 Wee. While the second proppant stage in such instances will require at least one ULW, the first proppant stage may contain either a conventional high-density proppant or a ULW.
Thus, for instance, the first proppant stage may be a banking fluid used to cause the initial propagation of the formation, allowing it to form a proppant bank.
The banking fluid may contain a conventional high-density proppant. A subsequent second proppant stage may include a ULW proppant, exhibiting a particle density substantially lower than the density of the conventional high-density proppant. For instance, the proppant of the subsequent proppant stage may have a density ranging between from about 1.25 g/cc to about 1.75 g/cc.

Proppant stages containing ULW proppants are less subject to settling than conventional proppant stages and are more easily transported to provide greater effective propped fracture length.
In addition, the method of the invention offers a reduction in costs and the potential for significantly improved effective propped fracture length.
As an example of the process of the invention, a hydrocarbon-bearing subterranean formation may be hydraulically fractured by first introducing into the formation a first proppant stage. This first proppant stage may be a first fracturing fluid and may be introduced at a pressure sufficient to initiate a fracture.
Alternatively, this first proppant stage may be introduced into the fracture after the fracture has been propagated. This initial (first) proppant stage may then be followed by fracturing the subterranean formation with a subsequent fracturing fluid, or second proppant stage. The number of successive proppant stages introduced into the fracture is determined by the preferences of the operator.
In a preferred embodiment of the invention, the fracturing fluid or "pad fluid"
used to initiate the fracture may contain at least one ULW proppant. Fracture conductivity is greatly improved by the incorporation of small amounts of a ULW
proppant in the pad fluid. The effective propped length of a fracture pumped with a ULW proppant-containing pad stage is greater than the effective propped fracture length of a fracture pumped with a substantially similar pad fluid not containing a ULW
proppant. By "substantially similar pad fluid" is principally meant a pad fluid identical to the ULW proppant-containing pad stage but not containing the ULW proppant.
Typically, the amount of ULW proppant in the pad fluid is between from about 0.12 to about 24, preferably between from about 0.6 to about 9.0, weight percent based on the total weight percent of the fracturing fluid. The proppant in the second proppant stage (following the pad stage) contains either a ULW proppant or a conventional high density proppant. The concentration of the ULW or conventional high density proppant in the second proppant stage is typically greater than or equal to the concentration of ULW proppant in the paid fluid. Preferably, the density differential between the proppant of the first proppant stage (pad fluid) and the second proppant stage is at least 0.2 g/cc.

The fracturing fluid may include any conventional fluid treatment such as crosslinked organoborate gels, guar or cellulosic based slickwaters, brines, linear gels and foams. The fracturing fluid may further contain a fine particulate, such as sand, for fluid loss control, etc.
In a preferred embodiment, the initial (first) fracturing fluid may contain a breaker. Further preferable, however, is the use of slick fluids, such as those exhibiting reduced water friction, as the initial stage which do not require a breaking fluid. Other proppant stages may optionally contain a breaker. The breaker can be any conventionally employed in the art to reduce the viscosity of the fracturing fluid including, but not being restricted to, thermostable polymers. Depending on the application, a breaker of predictable performance may be incorporated into the initial fracturing fluid or any of the proppant stages referred to herein for downhole activation.
A "spearhead" fluid may further precede the introduction of the fracturing or pad fluid to clean-up undesired products, such as ferrous sulfide and/or ferric oxide. Such fluids are typically introduced into the reservoir at fracturing rates and pressures which initiate the fracture in the formation and contain components known in the art.
The initial fracturing fluid, as well as any of the proppant stages referred to herein, may also contain other conventional additives common to the well service industry such as surfactants, biocides, gelling agents, cross-linking agents, curable resins, hardening agents, solvents, foaming agents, demulsifiers, buffers, clay stabilizers, acids, or mixtures thereof. In the practice of the invention, the fracturing fluid may be any carrier fluid suitable for transporting a mixture of proppant into a formation fracture in a subterranean well. Such fluids include, but are not limited to, carrier fluids comprising salt water, fresh water, liquid hydrocarbons, and/or nitrogen or other gases.
The initial fracturing fluid of the invention is pumped at a rate sufficient to initiate and propagate a fracture in the formation and to place the proppant into the fracture and form a bank. During the actual pumping the pH may be adjusted by the addition of a buffer, followed by the addition of the enzyme breaker, crosslinking agent, proppant or additional proppant and other additives if required. After deposition, the proppant material serves to hold the fracture open, thereby enhancing the ability of fluids to migrate from the formation to the wellbore through the fracture.

Typically, viscous gels or foams are employed as the fracturing fluid in order to provide a medium that will adequately suspend and transport the solid proppant, as well as to impair loss of fracture fluid to the formation during treatment (commonly referred to as "filterability" or "fluid loss"). As such, viscosity of the fracturing fluid may affect fracture geometry because fluid loss affects the efficiency of a treatment.
For example, when the rate of fluid loss to the formation equals or exceeds the rate of injection or introduction of fluid into a fracture, the fracture stops growing. Conversely, when the rate of fluid loss is less than the injection or introduction rate, taken together with other factors, a fracture continues to propagate. Excessive fluid loss thus results in fractures that are smaller and shorter than desired.
In one embodiment, the proppants disclosed herein may be introduced or pumped into a well as, for example, a saturated sodium chloride solution carrier fluid or a carrier fluid that is any other completion or workover brine having, for example, a specific gravity of from about 1 to about 1.5, alternatively from about 1.2 to about 1.5, farther alternatively about 1.2, at temperatures up to about 150 F. and pressures up to about 1500 psi. However, these ranges of temperature and closure stress are exemplary only, it being understood that the materials may be employed as proppant materials at temperatures greater than about 150 F and/or at closure stresses greater than about 1500 psi. It also being understood that core and/or layer materials may be selected by those of skill in the art to meet and withstand anticipated downhole conditions of a given application.
Preferably, the successive proppant stages (those proppant stages subsequent to the initial fracture proppant stage) include carrier systems that are gelled, non-gelled, or that have a reduced or lighter gelling requirement as compared to carrier fluids employed with conventional fracture treatment methods.
Conventional high-density proppants may be used in the first proppant stage, especially where the first proppant stage is used as the initial fracturing fluid, as well as in successive proppant stages (after the initial fracturing stage), may be any conventional proppant in the art. Such proppants include, for instance, quartz, glass, aluminum pellets, silica (sand) (such as Ottawa, Brady or Colorado Sands), synthetic organic particles such as nylon pellets, ceramics (including aluminosilicates such as "CARBOLITE,"

=
"NAPLITE" or "ECONOPROP"), sintered bauxite, and mixtures thereof. In addition, protective and/or hardening coatings, such as resins to modify or customize the density of a selected base proppant, e.g., ground walnut hulls, etc., resin-coated sand (such as "ACME BORDEN PR 6000" or "SANTROL TEMPERED HS"), resin-coated ceramic 5 particles and resin-coated sintered bauxite may be employed.
Preferred high-density proppants are sand, ceramic, sintered bauxite and resin coated proppant. Such proppants typically exhibit a high density, for instance greater than 2.65 g/cc. Typically, sand or synthetic fracture proppants are used. Such proppants are normally used in concentrations between about 1 to 18 pounds per gallon of 10 fracturing fluid composition, but higher or lower concentrations can be used as required.
The ULW proppant is defined as having a density less than or equal to 2.45 g/cc.
Generally, the density of the ULW proppant is less than or equal to 2,25, more preferably less than or equal to 2.0, even more preferably less than or equal to 1.75, most preferably less than or equal to 1.25 g/cc. Such proppants are less subject to settling and can be more 15 easily transported to provide greater effective propped fracture length.
Greater effective propped fracture length translates to improved stimulation efficiency, well productivity and, reservoir drainage.
In a preferred embodiment, the second proppant stage contains a proppant having a density less than the density of the proppant in the first proppant stage.
In a preferred 20 embodiment, successive third proppant stages contain a proppant having a density less than the density of the proppant of the second proppant stage. Preferably, the density differential between the proppant of the third proppant stage and the proppant of the second stage is greater than or equal to 0.2 g/cc. Thus, in a preferred embodiment of the invention, two or more proppants are pumped in successive stages; each successive stage 25 utilizing a proppant of lower density.
Such ULW proppants may be represented by relatively lightweight or substantially neutrally buoyant materials. One of the benefits of using such materials is that the requirements for the mixing equipment are minimized. For instance, when the carrier fluid is a brine, the only requirements on the mixing equipment is that it be 30 capable of (a) mixing the brine (dissolving soluble salts), and (b) homogeneously dispersing in the substantially neutrally buoyant particulate material.

' By "relatively lightweight" it is meant that the material has a density that is substantially less than a conventional proppant employed in hydraulic fracturing operations, e.g., sand or having a density similar to these materials. By "substantially neutrally buoyant", it is meant that a material having a density sufficiently close to the density of an ungelled or weakly gelled carrier fluid (e.g., ungelled or weakly gelled completion brine, other aqueous-based fluid, or other suitable fluid) to allow pumping and satisfactory placement of the proppant using the selected carrier fluid.
For example, urethane resin-coated ground walnut hulls having a specific gravity of from about 1.25 to about 1.35 grams/cubic centimeter may be employed as a substantially neutrally buoyant proppant in completion brine having a density of about 1.2. It will be understood that these values are exemplary only. As used herein, a "weakly gelled" carrier fluid is a carrier fluid having minimum sufficient polymer, viscosifier or friction reducer to achieve friction reduction when pumped down hole (e.g., when pumped down tubing, work string, casing, coiled tubing, drill pipe, etc.), and/or may be characterized as having a polymer or viscosifier concentration of from greater than 0 pounds of polymer per thousand gallons of base fluid to about 10 pounds of polymer per thousand gallons of base fluid, and/or as having a viscosity of from about 1 to about 10 centipoises. An ungelled carrier fluid may be characterized as containing about 0 pounds per thousand gallons of polymer per thousand gallons of base fluid. Such relatively lightweight and/or substantially neutrally buoyant materials are disclosed in U.S. Patent No.
6,364,018.
Exemplary of such relatively lightweight and/or substantially neutrally buoyant fracture proppant material is a ground or crushed walnut shell material that is coated with a resin to substantially protect and water proof the shell.
Such a material may have a specific gravity of from about 1.25 to about 1.35, and a bulk density of about 0.67.
Examples of types of materials suitable for use as relatively lightweight and/or substantially neutrally buoyant proppant materials include, but are not limited to, ground or crushed shells of nuts such as walnut, pecan, almond, ivory nut, brazil nut, etc.; ground or crushed seed shells (including fruit pits) of seeds of fruits such as plum, peach, cherry, apricot, etc.; ground or crushed seed shells of other plants such as maize (e.g. corn cobs or corn kernels), etc., crushed fruit pits or processed wood materials such as those derived from woods such as oak, hickory, walnut, poplar, mahogany, etc. including such woods that have been processed by grinding, chipping, or other form of particleization.
Those of skill in the art will understand that selection of suitable proppant will depend, in part, on the density of the carrier fluid and on whether it is desired that the selected proppant particle be relatively lightweight or substantially neutrally buoyant in the selected carrier fluid, and/or whether or not it is desired that the carrier fluid be non-gelled or non-viscosified.
The ULW proppants employed in the invention, including the relatively lightweight and/or substantially non-buoyant proppants, may be chipped, ground, crushed, or otherwise processed to produce particulate material having any particle size or particle shape suitable for use in the methods disclosed herein. Typically, the particle sizes of the proppants employed in the invention range from about 4 mesh to about 100 mesh, alternatively from about 8 mesh to about 60 mesh, alternatively from about 12 mesh to about 50 mesh, alternatively from about 16 mesh to about 40 mesh, and alternatively about 20 to 40 mesh. In one exemplary case, the proppant may ground walnut shells having a particle size of about 12/20 US mesh size in the first proppant stage and 20/40 US mesh size in the second proppant stage.
In a preferred mode, the second proppant stage is introduced into the formation immediately after the first proppant stage and the third proppant stages is introduced into the formation immediately after the second proppant stage without any intervening proppant stages.
Further, in a preferred mode, where the injection rate of a successive proppant stage is identical to the injection rate of the proppant stage introduced into the fracture immediately before the successive proppant stage or where the density of the proppant of the successive propp ant stage is identical or less than the density of the proppant of the proppant stage introduced into the fracture immediately before the successive proppant stage, the particle size of the proppant of the successive proppant stage is different from the particle size of the proppant of the proppant stage introduced into the fracture immediately before the successive proppant stage.

=

Fracture proppant sizes may be any size suitable for use in a fracturing treatment of a subterranean formation. It is believed that the optimal size of the proppant material may be dependent, among other things, on the size of the fracture, on in situ closure stress. As an example of the variance of the particle size in the invention, the particle size of the proppant of the first (initial) proppant stage may be 40 mesh while the particle size of the proppant of the second proppant size may be 30 mesh.
It is possible further that the particle size of the proppant between successive fractures may differ due to the coatings on the proppants. For instance, a proppant of a second proppant stage may be selected from at least one of ground or crushed nut shells, ground or crushed seed shells, ground or crushed fruit pits, processed wood, or a mixture thereof. A proppant of a first proppant stage may additionally include at least a portion of the individual particles of the particulate material above as core component which is at least partially surrounded by at least one layer component of the second proppant, the first proppant including a protective or hardening coating. Under such circumstances, if the core of the first proppant is identical to the core of the second proppant, the first proppant would have a greater particle size.
The potential for significantly improved effective propped fracture length is evidenced by use of the method of the invention. This may be due to the reduced cross-sectional flow area existing above the settled bank generated by the first proppant pumped. Assuming constant pumping rates at the wellbore, the reduced cross-sectional area 'artificially' increases the successive reduced density proppant slurry velocities th rough that section of the fracture, leading to improved transport and deeper placement of those slurry stages into the fracture than would be achieved within the created fracture in the absence of the proppant bank.
Under some circumstances deformable particles having a size substantially equivalent or larger than a selected fracture proppant size may be employed.
Such deformable particles are discussed above. For example, a deformable particulate material having a larger size than the fracture proppant material may be desirable at a closure stress of about 1000 psi or less, while a deformable particulate material equal in size to the fracture proppant material may be desirable at a closure stress of about 5000 psi or greater. However, it will be understood with benefit of this disclosure that these are just =

optional guidelines. In one embodiment, a deformable particle is selected to be at least as big as the smallest size of fracture proppant being used, and may be equivalent to the largest fracture proppant grain sizes. In either case, all things being equal, it is believed that larger fracture proppant and deformable particulate material is generally advantageous, but not necessary. Although deformable particulate material smaller than the fractured proppant may be employed, in some cases it may tend to become wedged or lodged in the fracture pack interstitial spaces. In one embodiment, deformable particles used in the disclosed method may have a beaded shape and a size of from about 4 mesh to about 100 mesh, alternatively from about 8 mesh to about 60 mesh, alternatively from about 12 mesh to about 50 mesh, alternatively from about 16 mesh to about 40 mesh, and alternatively about 20/40 mesh. Thus, in one embodiment, deformable particles may range in size from about 1 or 2 nun to about 0.1 mm; alternatively their size will be from about 0.2 mm to about 0.8 mm, alternatively from about 0.4 mm to about 0.6 mm, and alternatively about 0.6 mm. However, sizes greater than about 2 mm and less than about 0.1 mm are possible as well.
Deformable particles may be mixed and pumped with fracture proppant material throughout or during any portion of a hydraulic fracturing treatment in the practice of the disclosed method. However, in one embodiment when deformable particulate material is mixed with only a portion of a fracture proppant material pumped into a formation, it may be mixed with proppant during the latter stages of the treatment in order to dispose the deformable particulate material in the fracture pack at or near the point where the wellbore penetrates a subterranean formation.
Deformable particles having any density suitable for fracturing a subterranean formation may be employed in the practice of the disclosed method. In one embodiment specific gravity of deformable particulate material may range from about 0.3 to about 12, alternatively from about 0.4 to about 12, and further alternatively from about 0.5 to about 12. In another embodiment, the specific gravity of a deformable particulate material is from about 0.3 to about 3.5, alternatively from 0.4 to about 3.5, alternatively from about 0.5 to about 3.5, alternatively from about 0.6 to about 3.5, and even alternatively from about 0.8 to about 3.5. Alternatively a deformable particulate material having a specific gravity of from about 1.0 to about 1.8 is employed, and alternatively a deformable particle having a specific gravity of about 1.0 to about 1.1 is employed. In another specific embodiment, a particular divinylbenzene crosslinked polystyrene particle may have a bulk density of from about 0.4 to about 0.65, and alternatively of about 0.6. In another specific exemplary embodiment, a particular divinylbenzene crosslinked polystyrene particle may have a specific gravity of about 1.055. However, other specific gravities are possible. Advantageously, in one embodiment when deformable particles having a density less than that of a selected fracture proppant material are employed, reduced treating pressures and concentration levels of potentially formation-damaging gelled or viscous fluids may be employed. This may allow higher treating rates and/or result in higher formation productivity.
Lastly, in a preferred mode, the second or ultimate proppant stage is injected into the fracture at a rate different from the injection rate of the first or penultimate proppant stage. Preferably, the rate of injection of the ultimate proppant stage is less than the rate of injection of the penultimate proppant stage. Typically, the rate of injection of a proppant stage into the formation or fracture in accordance with the invention is from about 5 barrels per minute to as high as 270 barrels per minute. Generally, the rate of injection is no greater than about 150 barrels per minute.
Additionally, the same arguments for this approach would apply when using more viscous fluids such as linear or crosslinked fluids, particularly when considering applications in more rigorous downhole environments (i.e., higher temperatures).
Further, subsequent to creating the fracture, it may be advantageous to reverse the process and fracture back to the wellbore filling the wellbore. This can be achieved in sequential steps such that at least one of the following conditions prevails after each successive stage:
(1) the density of the successive (ultimate) stage being injected into the wellbore is generally less than the density of the stage introduced to the wellbore just prior (penultimate) to the successive stage;
(2) the rate of injection of the ultimate stage being injected into the fracture is less than the rate of injection of the penultimate stage; or (3) the particle size of the proppant of the ultimate stage being injected into the fracture is different than the particle size of the proppant of the penultimate stage.

The following examples will illustrate the practice of the present invention in its preferred embodiments. Other embodiments within the scope of the claims herein will be apparent to one skilled in the art from consideration of the specification and practice of the invention as disclosed herein. It is intended that the specification, together with the examples, be considered exemplary only, with the scope and spirit of the invention being indicated by the claims that follow.
Examples Example 1 (Comparative). This Example demonstrates the settling rates for Ottawa sand and Walnut Hull ULW.
ULW 1.75 is porous ceramic material from Carbo Ceramics, Inc. treated with 2%
by weight of particle epoxy inner coating/penetrating material (epoxy is reaction product of epichlorohydrin and bis-phenol A) and with 2% by weight of particle phenol formaldehyde resin outer coating material. It can be characterized as a porous ceramic particle with the roundness and sphericity common to ceramic proppants. The porosity averages 50%, yielding a bulk density of 1.10 to 1.15g/cm3. Median-sized 20/40 particles of the ULW-1.75 and Ottawa sand were used. The 20/40 Ottawa sand has an average bulk density of 1.62 g/cm with a specific gravity of 2.65. The ULW-1.75 has a bulk density of 1.05 to 1.10.
Static particle settling evaluations were conducted in fresh water to determine the differences in settling rate between the conventional proppant and the ULW
particles.
Median sized 20/40 particles of each proppant were used for the evaluations.
Stokes Law calculations giving the fall velocity in ft/minute are presented in Table 1 and were calculated as:
V =1.15x103(c õp I pflõid)(Sp.Gr.prop ¨ Sp.Gr.flõ,d) where velocity is in ft/min., diameter d is the average particle diameter and, J2 is fluid viscosity in cps.

Static Settling Rates for Proppants as Derived by Stoke's Law 20/40 Proppant Sp.Or. Settling Velocity ft/minute Ottawa sand 2.65 16.6 ULW-1.75 1.75 11.2 Large-scale slot flow tests were conducted to characterize the dynamic settling rates of the ultra-lightweight proppant. Proppant transport characteristics were studied at ambient temperature through a glass slot. The transparent slot is a 22-inch high, 16-ft long and 0.5-inch wide parallel plate device. One thousand gallons of test fluid was prepared and the fluid rheology was measured using a standard Farm 35 viscometer. Fluid was then transferred to a 200-gallon capacity ribbon blender and pumped through the test loop to fill the transparent slot model. Once the slot was filled with the test fluid, proppant was added to the blender to prepare a slurry of the desired concentration. The slicicwater fluid used in the test exhibited an average viscosity of 5 to 7 cps throughout the series of tests.
The shear rate in the slot is given by the equation:
til y = [sec']1.925q[gp (14in.1)2(H{fti where q is the rate in gallons per minute, w is width in inches and H is height in feet.
Fluid velocity through this slot model is given by:
v[m / sec] = 0.00815q[gPm]
(wrin.1)(11[11]) The proppant transport behavior of each test slurry was observed through the slot at various flow rates. During these tests, the proppant distribution was continually recorded with video cameras as well as manually by observation. All bed height measurements for this work were taken close to the discharge end of the slot flow cell.
Ottawa sand slurried in slickwater was observed to begin settling upon entrance to the slot even at the maximum fluid pump rate. Within 12 minutes at 90 gpm ( 378sec-1 shear rate), the bed height was 15 inches, 68% of the total height of the 22 in. slot.

, Table 2 below shows the results in tabular form. Only at shear rates in excess of 1000 sec-1 was the dynamic Ottawa Sand proppant fall rate mitigated in the slicicwater test fluid. As flow rates were lowered to 30 gpm, the Ottawa proppant bed reached its maximum bed height of 19.5 inches or 91.25% of the slot height. Above the proppant bed, the shear rate reached 1,414 sec-1, at which point additional settling did not occur.
As the rate increased from 30 to 40 gpm (1,919 sec-1), the bed height was actually reduced.
_ ' =-::,'-- '' ';....,. -:::".....'õ,c,,:.':.'_:41ATAIStg,2";',.P:.V`
,.;.f%,:;1',:.õ.!-",,i,k,1:'.7','',,,i:
lptio Ot*,,t Pl'OPIWS1,6flik,If ' -0,1-6'bext`
;.iiiiiitde ' :. --s.di3iik,:õ;',-.;-'r,Heightttil. $4,41-:,19v.,s4.45.1.5.;,,,,:-. :

1 90 0.25 383 - 443 12 90 1.25 381 1201 14 60 1.27 252 825 18 60 1.38 252 825 19 40 1.39 168 677 28 40 1.54 170 1076 30 30 1.58 116 858 42 30 1.67 171 1414 43 40 1.67 171 1919 45 40 1.52 169 1070 The ULW-1.75 test was initiated at 90 gpm. ULW-1.75 was observed to be subject to some settling at 90 gpm, with the bed height growing to 4 inches.
The fluid rate was lowered to 80 gpm and bed height grew to 6 inches. As the rates were reduced incrementally down to 30 gpm, the ULW-1.75 bed was observed to grow with reduced rate to 12 inches. The rate was lowered further to 5 gpm and the bed height grew to 19 inches or 86% of the total slot height. As observed in previous tests, as the rate is increased incrementally, bed height decreases due to erosion and fluidization of the bed.
The ULW-1.75 results are presented in Table 3.
Tune . 'Mid Rae Prop Bed Slot,Shear . 'Above be.d,.
Minute Gpm Height' = 'Sec-1 . , sec-1 .. , 0 90 0.0 378 378 7 90 0.33 378 463 8 80 0.38 337 423 11 80 0.54 337 478 12 70 0.58 295 432 15 60 0.71 252 412 17 60 0.79 252 445 18 50 0.83 210 386 tt,if sfi 20 50.4 0.92 212 425 22 39 0.96 164 345 28 _ 31 1.29 130 443 29 20 1.33 81 299 33 8 1.44 34 159 34 5.1 1.46 21 106 35 20 1.54 84 534 37 20.5 1.58 86 640 38 40.4 1.52 170 1006 40 50.6 1.46 213 1048 45 60.2 1.33 253 933 Both of the tested materials settle progressively more as the velocity decreases.
Due to the decreased density, the ULW is more easily placed back in flow as the rate is increased. The reduced density materials require less shear increase to fluidize the proppant bed. Ottawa sand was observed to require in excess of 1,500 sec-1 to transport the proppant in slickwater. and almost 2,000 sec-1 of shear to begin to fluidize the proppant bed. The ULW-1.75 transporting at shear rates of 500 sec-1 and fluid shear rates of 800 sec-1 were needed to fluidize the proppant bed.
Example 2. This Example illustrates use of the combination of both sand and walnut hull ULW proppants.
One hundred pounds of sand and 50 pounds of walnut hull ULW proppant were blended together in a ribbon blender and circulated throughout the system. The blend displayed behavior almost identical to their individual tests, respectively.
The sand settled even at very high flow rates, throughout the length of the slot as in the earlier test.
Because sand built bed height continuously throughout the test, the ULW
proppant stayed suspended. Lateral velocity was increased by the sand bed, so very little ULW proppant was entrained in the sand bed, This is attributable to the fact that the sand bed height artificially increased lateral velocities in the slot to levels that maintained the ULW proppant in suspension for the most part. Most of the sand settled out in the slot before any ULW proppant began to settle. Rates had to be dropped down to below gpm in order to initiate larger scale settling of the ULW material and by that time, there was little sand left to settle.

The process presents a suitable means to improve penetration of proppant into a productive horizon. Both proppants behave independently from each other, yet the settling of the heavier proppant improves the ability of the lighter proppant to move deeper in the fracture by partially occluding the open flow space. It is reasonable to assume that the behavior will extend to more than two proppants in a given slurry and as such may offer additional advantages in fracture placement and propagation.
This offers advantages for slicicwater fracturing operations as they are currently conducted.
Example 3. This Example demonstrates the improvement in fracture conductivity by use of a ULW proppant as a component in a pad fluid.
A fracture was simulated using the Mfrac three-dimensional hydraulic fracturing simulator of Meyer & Associates, Inc. using a simple 3-layer isotropic homogeneous 0.1 mD permeability gas reservoir model, 40 acre spacing. The fracture was designed to be placed into the zone at a theoretical depth of 9800 feet and the model was run in full 3-D
mode. The fracturing fluid was a crosslinked organoborate. The pad fluid was injected into the model at a rate of 50 barrels per minute (bpm). The fracturing fluid of Example 3A contained no ULW proppant. In Example 3B, a very small amount (0.5 pounds per gallon) of LitePropTM 125 lightweight proppant, a product of BJ
Services Company, was added to the fracturing fluid. The second and subsequent stages employed sand as proppant wherein the sand concentration was approximately 8 ppg.
Since the Mfrac model does not make calculations for a partial monolayer, the conductivity of the proppant was artificially increased at a concentration of 0.5 lbs/sq. ft.
Table 4 shows the pump schedule utilized for Example 3A and Table 5 shows the pump schedule for Example 3B.

.

, .

Stage Slurry Rate Stage Liquid Stage Time Stage Type Fluid Type Prop Type Prop Conc. Prop Damage No. Volume Factor (-) (bpm) (U.S. gal) (min) 0 0 0 (Ibm/gal) (-) 1 50 20000 9.5238 Pad B095 0000 0 0 2 50 10000 5.1929 Prop 13095 0001 2 0 3 50 10000 5.6239 Prop 8095 0001 4 0 4 50 10000 6.0548 Prop 8095 0001 6 0 50 10000 6.4858 Prop 13095 0001 8 0 6 50 9600 4.5714 Flush S020 0000 0 0 Wellbore Fluid Type: 2% KCI
5 8095 - Spectra Frac HT 3500 w/ 4.0 gpt 8F-71, 2.0 gpt XLW-56 crosslinker, products of BJ Services Company, Fluid Type: SG20 - 2% KCI guar slickwater 204 Proppant Type: 0000 - No Prop, Slug Proppant Type: 0001 - 20/40 Jordan Sand Stage Slurry Rate Stage Liquid Stage Time Stage Type Fluid Type Prop Type Prop Conc. Prop Damage No. Volume Factor 0 (bM) (U.S. gal) (min) (-) (-) (-) (Ibm/gal) (-) 1 50 20000 9.9803 Pad 8095 SG19 0.5 0 2 50 10000 5.1929 Prop B095 0001 2 0 3 50 10000 5.6239 Prop B095 0001 4 0 4 50 10000 6.0548 Prop 8095 0001 6 0 5 50 10000 6.4858 Prop 13095 0001 8 0 6 50 9600 4.5714 Flush SG20 0000 0 0 Wellbore Fluid Type: 2% KCI
8095 - Spectra Frac HT 3500 w/ 4.0 gpt BF-7L, 2.0 gpt XLW-56 crosslinker, products of BJ Services Company, Fluid Type: SG20 - 2% KCI guar slicicwater 20#
Prappant Type: SG19 - ULW 125 partial monolayer Proppant Proppant Type: 0001 - 20/40 Joodan Sand Proppant Type: 0000 - No Prop, Slug Fracture conductivity between the proppant-packed fracture and that of the native reservoir, mathematically defined as:
(proppant pack permeability x fracture width) /
(formation permeability x propped fracture half length) is illustrated in the conductivity profiles of FIGs. 1 and 2 after closure of the fracture.
FIG. 1 is a 2D depiction of the fracture of injection of the fracturing fluid of Example 3A.
FIG. 2 contrasts injection of the fracturing fluid of Example 3B. In both figures, the "created fracture area," represented as 10, is the area of the reservoir traversed by the propagating fracturing fluid pad. The "propped fracture area", 20, is contributory to well stimulation, and represents the area of the reservoir "propped open" to provide improved fracture conductivity. The created but unpropped area 30, "heal" upon fracture closure and, thus, is not considered to be stimulated.

As set forth in FIGs. 1 and 2, the propped fracture length is increased from approximately 320 ft to approximately 460 feet by the addition of the ULW
proppant and all of the proppant ends in the pay zone, defined by the area within 40 and 50. The Figures demonstrate greatly improved fracture conductivity by the incorporation of a ULW proppant into a previously non-proppant laden pad fluid. This results in an enhanced fracture length which leads to enhanced well productivity, producible well reserves and ultimate expected recovery. Use of the ULW proppants avoid failure due to settling and bridging of the particles.
The foregoing disclosure and description of the invention is illustrative and explanatory thereof, and various changes in the size, shape, and materials, as well as in the details of illustrative construction and assembly, may be made without departing from the spirit of the invention.

Claims (79)

CLAIMS:
1. A method of fracturing a subterranean formation comprising:
pumping a pad fluid into the formation at a pressure sufficient to initiate a fracture;
introducing a first proppant stage into the fracture, the first proppant stage containing an ultra lightweight (ULW) proppant having a density less than or equal to 2.45 g/cc; and introducing a second proppant stage into the fracture, the second proppant stage containing an ultra lightweight (ULW) proppant having a density less than or equal to 2.45 g/cc, wherein the density of the second proppant stage is greater than the density of the first proppant stage wherein the effective propped length of the fracture after pumping of the second proppant stage is greater than the effective propped length of the fracture prior to the injection of the second proppant stage and further wherein at least one of the pad fluid, the first proppant stage or the second proppant stage contains slickwater.
2. The method of Claim 1, wherein the pad fluid, the first proppant stage and the second proppant stage contains slickwater.
3. The method of Claim 1, wherein the particle size of the ULW proppant in the first proppant stage and the second proppant stage is between from 8 mesh to 100 mesh.
4. The method of Claim 3, wherein the particle size of the ULW proppant in the first proppant stage and the second proppant stage is between from 8 mesh to 100 mesh.
5. The method of Claim 4, wherein the particle size of the ULW proppant in the first proppant stage and the second proppant stage is between from 16 mesh to 40 mesh.
6. The method of Claim 5, wherein the particle size of the ULW proppant in the first proppant stage and the second proppant stage is between from 20 mesh to 40 mesh.
7. A method of stimulating a hydrocarbon-bearing subterranean formation which comprises:
(a) pumping a pad fluid into the formation to initiate a fracture;
(b) pumping a proppant stage into the fracture which contains an ultra lightweight (ULW) proppant having a density less than or equal to 2.45 Wee.; and (c) forming a partial monolayer of ULW proppant in the fracture wherein at least one of the pad fluid or the proppant stage contains slickwater.
8. The method of Claim 7, wherein the density of the ULW proppant of the proppant stage is less than or equal to 2.0 g/cc.
9. The method of Claim 8, wherein the density of the ULW proppant of the proppant stage is less than or equal to 1.75 g/cc.
10. The method of Claim 9, wherein the density of the ULW proppant of the proppant stage is less than or equal to 1.25 g/cc.
11. The method of Claim 10, wherein the ULW proppant is other than ground or crushed shells of nuts, ground or crushed seed shells of seeds of fruits, ground or crushed seed shells of plants, crushed fruits pits or processed wood materials.
12. The method of Claim 7, wherein the pad fluid contains a proppant.
13. The method of Claim 12, wherein the proppant in the pad fluid is a ULW
proppant.
14. The method of Claim 13, wherein the concentration of the ULW proppant in the pad fluid is an amount sufficient to create a partial monolayer of the ULW
proppant in the initiated fracture.
15. The method of Claim 7, wherein the ULW proppant is other than ground or crushed shells of nuts, ground or crushed seed shells of seeds of fruits, ground or crushed seed shells of plants, crushed fruits pits or processed wood materials.
16. The method of Claim 7, wherein the particle size of the ULW proppant in the proppant stage is between from 8 mesh to 100 mesh.
17. The method of Claim 16 wherein the particle size of the ULW proppant in the proppant stage is between from 16 mesh to 40 mesh.
18. The method of Claim 17, wherein the particle size of the ULW proppant in the proppant stage is between from 20 mesh to 40 mesh.
19. A method of stimulating a hydrocarbon-bearing subterranean formation which comprises:
(a) pumping a first proppant stage into the formation to initiate or extend a fracture;

(b) pumping a second proppant stage into the fracture which contains an ultra lightweight (ULW) proppant having a specific gravity less than or equal to 2.45 g/cc, wherein the ULW proppant is pumped in the proppant stage of step (b) at a constant rate;
and further wherein either:
the concentration of the ULW proppant in the second proppant stage;
or (ii) the proppant size of the ULW proppant in the second proppant stage;
or (iii) both the concentration and proppant size of the ULW proppant in the second proppant stage remains constant during pumping and further wherein at least one of the first proppant stage or the second proppant stage contains slickwater.
20. The method of Claim 19, wherein the density of the ULW proppant of the second proppant stage is less than or equal to 2.0 g/cc.
21. The method of Claim 20, wherein the density of the ULW proppant of the second proppant stage is less than or equal to 1.75 g/cc.
22. The method of Claim 21, wherein the density of the ULW proppant of the second proppant stage is less than or equal to 1.25 g/cc.
23. The method of Claim 19, wherein the ULW proppant of the second proppant stage is other than ground or crushed shells of nuts, ground or crushed seed shells of seeds of fruits, ground or crushed seed shells of plants, crushed fruits pits or processed wood materials.
24. The method of Claim 19, wherein the concentration of the ULW proppant in the second proppant stage is an amount sufficient to create a partial monolayer of the ULW
proppant in the fracture.
25. The method of Claim 19, wherein the proppant size of the ULW proppant in the second proppant stage remains constant during pumping.
26. The method of Claim 25, wherein the concentration of the ULW proppant in the second proppant stage remains constant during pumping.
27. The method of Claim 19, wherein the particle size of the ULW proppant in the second proppant stage is between from 8 mesh to 100 mesh.
28. The method of Claim 27, wherein the particle size of the ULW proppant in the second proppant stage is between from 16 mesh to 40 mesh.
29. The method of Claim 28, wherein the particle size of the ULW proppant in the second proppant stage is between from 20 mesh to 40 mesh.
30. A method of hydraulically fracturing a hydrocarbon-bearing subterranean formation which comprises:
(a) pumping a first proppant stage containing an ultra lightweight (ULW) proppant having a specific gravity less than or equal to 1.25 g/cc either into a propagated fracture or into the formation at a pressure sufficient to fracture the formation; and (b) pumping a second proppant stage containing a ULW proppant having a specific gravity less than or equal to 1.25 g/cc into the fracture wherein at least one of the first proppant stage or the second proppant stage contains slickwater and wherein a partial monolayer of proppant is formed in the fracture.
31. The method of Claim 30, wherein a partial monolayer of proppant is formed in the fracture from step (a).
32. The method of Claim 30, wherein the density differential between the proppant of the first proppant stage and the proppant of the second proppant stage is such as to form a partial monolayer of proppant in the fracture.
33. The method of Claim 30, wherein the particle size of the ULW proppants in the first proppant stage and the second proppant stage is between from 8 mesh to 100 mesh.
34. The method of Claim 33, wherein the particle size of the ULW proppant in the first proppant stage and the second proppant stage is between from 16 mesh to 40 mesh.
35. The method of Claim 34, wherein the particle size of the ULW proppant in the first proppant stage and the second proppant stage is between from 20 mesh to 40 mesh.
36. The method of Claim 30, wherein prior to step (a), a pad fluid is pumped into the formation to initiate a fracture.
37. The method of Claim 30, wherein the density of the second proppant stage is greater than the density of the first proppant stage.
38. A method of stimulating a hydrocarbon-bearing subterranean formation which comprises:
(a) purming a pad fluid into the formation to initiate a fracture;
(b) pumping a proppant stage into the fracture which contains an ultra lightweight (ULW) proppant having a less than or equal to 2.45 g/cc, wherein the ULW
proppant is pumped in the proppant stage of step (b) at a constant rate and further wherein either:
(i) the concentration of the ULW proppant in the proppant stage of step (b); or (ii) the proppant size of the ULW proppant in the proppant stage of step (b); or (iii) both the concentration and proppant size of the ULW proppant in the proppant stage of step (b) remains constant during pumping and further wherein at least one of the pad fluid or the proppant stage contains slickwater.
39. The method of Claim 38, wherein the density of the ULW proppant of the proppant stage is less than or equal to 2.0 g/cc.
40. The method of Claim 39, wherein the density of the ULW proppant of the proppant stage is less than or equal to 1.75 g/cc.
41. The method of Claim 40, wherein the density of the ULW proppant of the proppant stage is less than or equal to 1.25 g/cc.
42. The method of Claim 38, wherein the ULW proppant is other than ground or crushed shells of nuts, ground or crushed seed shells of seeds of fruits, ground or crushed seed shells of plants, crushed fruits pits or processed wood materials.
43. The method of Claim 38, wherein the pad fluid contains a proppant.
44. The method of Claim 43, wherein the proppant of the pad fluid is a ULW
proppant.
45. The method of Claim 44, wherein the concentration of the ULW proppant in the pad fluid is an amount sufficient to create a partial monolayer of the ULW
proppant in the initiated fracture.
46. The method of Claim 38, wherein the ULW proppant is other than ground or crushed shells of nuts, ground or crushed seed shells of seeds of fruits, ground or crushed seed shells of plants, crushed fruits pits or processed wood materials.
47. The method of Claim 38, wherein the proppant size of the ULW proppant in the proppant stage remains constant during pumping.
48. The method of Claim 47, wherein the concentration of the ULW proppant in the proppant stage remains constant during pumping.
49. The method of Claim 38, wherein the particle size of the ULW proppant in the proppant stage is between from 8 mesh to 100 mesh.
50. The method of Claim 49, wherein the particle size of the ULW proppant in the proppant stage is between from 16 mesh to 40 mesh.
51. The method of Claim 50, wherein the particle size of the ULW proppant of the proppant stage is between from 20 mesh to 40 mesh.
52. A method of stimulating a hydrocarbon-bearing subterranean formation which comprises:
(a) pumping a first proppant stage either into a propagated fracture or into the formation at a pressure sufficient to fracture the formation, wherein the first proppant stage contains an ultra lightweight (ULW) proppant having a density less than or equal to 2.45 g/cc;
(b) pumping into the fracture a second proppant stage containing a proppant having a density greater than 2.45 g/cc; and (c) pumping a third stage into the fracture wherein at least one of the following conditions prevails:
the third stage does not contain a proppant;
(ii) the third stage contains an U LW proppant having a density less than or equal to 2.45 g/cc; or (iii) the third stage contains a proppant having a density greater than 2.45 g/cc and wherein at least one of the first proppant stage, the second proppant stage or the third stage contains slickwater.
53. The method of Claim 52, wherein the ULW proppant of the first proppant stage has a density less than or equal to 1.25 g/cc.
54. The method of Claim 52, wherein the third stage contains a ULW proppant having a density less than or equal to 1.25 g/cc.
55. A method of stimulating a hydrocarbon-bearing subterranean formation which comprises:
(a) pumping a pad fluid into the formation to initiate a fracture;
(b) pumping a proppant stage into the fracture which contains a proppant having a density greater than 2.45 g/cc; and then (c) pumping another proppant stage into the fracture which contains an ultra lightweight (ULW) proppant having a density less than or equal to 2.45 g/cc wherein at least one of the pad fluid, proppant stage or another proppant stage contains slickwater.
56. The method of Claim 55, wherein the proppant stage of step (c) forms a partial monolayer of proppant in the fracture.
57. A method of hydraulically fracturing a hydrocarbon-bearing subterranean formation which comprises:
pumping a fracturing fluid containing a first proppant stage either into a propagated fracture or into the formation at a pressure sufficient to fracture the formation; and pumping a fracturing fluid containing a second proppant stage into the fracture wherein at least one of the following conditions prevails:
the density differential between the first proppant stage and the second proppant stage is greater than or equal to 0.2 g/cc and either the first proppant stage and/or the second proppant stage contains an ultra lightweight (ULW) proppant;
(ii) the proppant of the first proppant stage and/or the second proppant stage contains a ULW proppant and the rate of injection of the second proppant stage into the fracture is different from the rate of injection of the first proppant stage;
(iii) the proppant of the first proppant stage and/or the second proppant stage contains a ULW proppant and the particle size of the proppant of the second proppant stage is different from the particle size of the proppant of the first proppant stage; or (iv) the first proppant stage comprises a proppant having a density greater than 2.45 g/cc; and the second proppant stage comprises an ultra lightweight (ULW) proppant having a density less than or equal to 2.45 g/cc.
and further wherein the fracturing fluid of the first proppant stage, the fracturing fluid of the second proppant stage, or both the fracturing fluid of the first proppant stage and second proppant stage contain slickwater.
58. A method of hydraulically fracturing a hydrocarbon-bearing subterranean formation which comprises introducing into a formation a fracturing fluid containing a first proppant stage and a fracturing fluid containing a second proppant stage, wherein each of the first proppant stage and second proppant stage contains an ultra lightweight (ULW) proppant having a density less than or equal to 2.45 g/cc and further wherein the ULW
proppant of the first proppant stage and/or the second proppant stage is other than ground or crushed shells of nuts, ground or crushed seed shells of seeds of fruits, ground or crushed seed shells of plants, crushed fruits pits or processed wood materials and is capable of withstanding closure stresses greater than 1500 psi at a temperature greater than 150° F.
and further wherein the fracturing fluid of the first proppant stage, the fracturing fluid of the second proppant stage, or both the fracturing fluid of the first proppant stage and second proppant stage contain slickwater.
59. A method of hydraulically fracturing a hydrocarbon-bearing subterranean formation which comprises pumping a fracturing fluid containing a first proppant stage either into a propagated fracture or into the formation at a pressure sufficient to fracture the formation and pumping a fracturing fluid containing a second proppant stage into the fracture, wherein the proppant of the first proppant stage and/or the second proppant stage contains a ULW proppant and the particle size of the proppant of the second proppant stage is different from the particle size of the proppant of the first proppant stage; and further wherein the fracturing fluid of the first proppant stage, the fracturing fluid of the second proppant stage, or both the fracturing fluid of the first proppant stage and second proppant stage contain slickwater.
60. A method of stimulating a hydrocarbon-bearing subterranean formation which comprises introducing into a formation a fracturing fluid containing an ultra lightweight (ULW) proppant having a density less than or equal to 2.45 g/cc, wherein the ULW proppant is other than ground or crushed shells of nuts, ground or crushed seed shells of seeds of fruits, ground or crushed seed shells of plants, crushed fruits pits or processed wood materials and further wherein the ULW proppant is capable of withstanding closure stresses greater than 1500 psi at a temperature greater than 150° F., and further wherein the fracturing fluid contains slickwater.
61. A method of fracturing a subterranean formation comprising:
pumping into an initiated fracture in the formation a first proppant stage containing an ultra lightweight (ULW) proppant having a density less than or equal to 2.45 g/cc;
pumping a fracturing fluid into the fracture; and pumping a second proppant stage into the fracture, the second proppant stage containing an ultra lightweight (ULW) proppant having a density less than or equal to 2.45 g/cc wherein the effective propped length of the fracture after pumping of the second proppant stage is greater than the effective propped length of the fracture prior to pumping of the second proppant stage; and further wherein at least one of the first proppant stage or the second proppant stage contains slickwater. .
62. The method of Claim 61, wherein the density differential between the second proppant stage and the first proppant stage is greater than or equal to 0.2 g/cc.
63. The method of Claim 61, wherein the density of the ULW proppant of the first proppant stage is less than or equal to 2.0 g/cc.
64. The method of Claim 63, wherein the density of the ULW proppant of the first proppant stage is less than or equal to 1.75 g/cc.
65. The method of Claim 64, wherein the density of the ULW proppant of the first proppant stage is less than or equal to 1.25 g/cc.
66. The method of Claim 61, wherein the ULW proppant of the first proppant stage and the ULW proppant of the second proppant stage is the same material.
67. The method of Claim 61, wherein the particle size of the ULW proppant in the first proppant stage and the second proppant stage is between from about 8 mesh to about 100 mesh.
68. The method of Claim 61, wherein the fracturing fluid contains a crosslinked organoborate gel, guar, cellulosic based slickwaters, brines, linear gels or a foam.
69. A method of stimulating a hydrocarbon-bearing subterranean formation which comprise pumping a penultimate proppant stage and an ultimate proppant stage into a fracture in the formation, wherein at least one of the following conditions prevail:
(i.) at least one of the proppant stages contains a first proppant and a second proppant wherein at least one of the first or second proppant is a ULW
proppant having a density less than or equal to 2.45 g/cc;
(ii.) the density differential between the penultimate proppant stage and the ultimate proppant stage is greater than or equal to 0.2 g/cc and either the penultimate proppant stage, the ultimate proppant stage or both the penultimate stage and the ultimate proppant stage contains a ULW proppant;
(iii.) both the penultimate proppant stage and the ultimate proppant stage contain ULW proppants;
(iv.) the penultimate proppant stage; the ultimate proppant stage; or both the penultimate proppant stage and the ultimate proppant stage contains a ULW
proppant and the rate of injection of the ultimate proppant stage into the fracture is different from the rate of injection of the penultimate proppant stage; or (v.) the proppant of the penultimate proppant stage, the ultimate proppant stage or both the penultimate proppant stage and the ultimate proppant stage contains a ULW
proppant and the particle size of the ultimate proppant stage is different from the particle size of the penultimate proppant stage; and further wherein a fracturing fluid is introduced into the fracture after the penultimate proppant stage but prior to the ultimate proppant stage, and further wherein at least one of the penultimate or ultimate proppant stages contains slickwater.
70. The method of Claim 69, wherein a partial monolayer of ULW proppant is formed in the fracture.
71. The method of Claim 69, wherein the fracturing fluid contains a crosslinked organoborate gel, guar, cellulosic based slickwaters, brines, linear gels or a foam.
72. The method of Claim 69, wherein the density of the ULW proppant of the penultimate proppant stage, the ultimate proppant stage or both the penultimate proppant stage and the ultimate proppant stage is less than or equal to 2.0 g/cc.
73. The method of Claim 69, wherein the ULW proppant of the penultimate proppant stage, the ultimate proppant stage or both the penultimate proppant stage and the ultimate proppant stage is other than ground or crushed shells of nuts, ground or crushed seed shells of seeds of fruits, ground or crushed seed shells of plants, crushed fruits pits or processed wood materials.
74. The method of Claim 70, further comprising introducing a pad fluid into the formation in order to initiate the fracture.
75. A method of stimulating a hydrocarbon-bearing subterranean formation which comprises:
pumping into an initiated fracture in the formation a first proppant stage containing an ultra lightweight (ULW) proppant having a density less than or equal to 2.45 g/cc; and pumping a second, penultimate and ultimate proppant stages into the fracture, the proppant of the second, penultimate and ultimate proppant stages containing an ultra lightweight (ULW) proppant having a density less than or equal to 2.45 g/cc wherein (i) the effective propped length of the fracture after pumping of the second proppant stage is greater than the effective propped length of the fracture prior to pumping of the second proppant stage; (ii) the effective propped length of the fracture after pumping of the penultimate proppant stage is greater than the effective propped length of the fracture prior to pumping the penultimate proppant stage; and (iii) the effective propped length of the fracture after pumping of the ultimate proppant stage is greater than the effective propped length of the fracture prior to pumping the ultimate proppant stage; and (iv) at least one of the first proppant stage, second proppant stage, penultimate proppant stage or ultimate proppant stage contains slickwater and further wherein a fracturing fluid is introduced into the formation between one or more of the following stages: the first proppant stage and the second proppant stage; the second proppant stage and the penultimate proppant stage; and the penultimate proppant stage and the ultimate proppant stage.
76. The method of Claim 75, wherein the fracturing fluid contains a crosslinked organoborate gel, guar, cellulosic based slickwaters, brines, linear gels or foams.
77. The method of Claim 75, wherein the density of the ULW proppant of the first proppant stage, second proppant stage, penultimate proppant stage and ultimate proppant stage is less than or equal to 2.0 g/cc.
78. The method of Claim 75, wherein the ULW proppant of the first proppant stage, second proppant stage, penultimate proppant stage or ultimate proppant stage is other than ground or crushed shells of nuts, ground or crushed seed shells of seeds of fruits, ground or crushed seed shells of plants, crushed fruits pits or processed wood materials.
79. The method of Claim 75, wherein a partial monolayer of the ULW proppant is created in the fracture.
CA2644213A 2003-03-18 2004-03-18 Method of treating subterranean formations using mixed density proppants or sequential proppant stages Expired - Lifetime CA2644213C (en)

Priority Applications (1)

Application Number Priority Date Filing Date Title
CA2795417A CA2795417C (en) 2003-03-18 2004-03-18 Method of treating subterranean formations using mixed density proppants or sequential proppant stages

Applications Claiming Priority (5)

Application Number Priority Date Filing Date Title
US45571703P 2003-03-18 2003-03-18
US60/455,717 2003-03-18
US50882203P 2003-10-03 2003-10-03
US60/508,822 2003-10-03
CA002519144A CA2519144C (en) 2003-03-18 2004-03-18 Method of treating subterranean formations using mixed density proppants or sequential proppant stages

Related Parent Applications (1)

Application Number Title Priority Date Filing Date
CA002519144A Division CA2519144C (en) 2003-03-18 2004-03-18 Method of treating subterranean formations using mixed density proppants or sequential proppant stages

Related Child Applications (1)

Application Number Title Priority Date Filing Date
CA2795417A Division CA2795417C (en) 2003-03-18 2004-03-18 Method of treating subterranean formations using mixed density proppants or sequential proppant stages

Publications (2)

Publication Number Publication Date
CA2644213A1 CA2644213A1 (en) 2004-09-30
CA2644213C true CA2644213C (en) 2013-10-15

Family

ID=33032701

Family Applications (2)

Application Number Title Priority Date Filing Date
CA2644213A Expired - Lifetime CA2644213C (en) 2003-03-18 2004-03-18 Method of treating subterranean formations using mixed density proppants or sequential proppant stages
CA002519144A Expired - Lifetime CA2519144C (en) 2003-03-18 2004-03-18 Method of treating subterranean formations using mixed density proppants or sequential proppant stages

Family Applications After (1)

Application Number Title Priority Date Filing Date
CA002519144A Expired - Lifetime CA2519144C (en) 2003-03-18 2004-03-18 Method of treating subterranean formations using mixed density proppants or sequential proppant stages

Country Status (3)

Country Link
US (4) US7210528B1 (en)
CA (2) CA2644213C (en)
WO (1) WO2004083600A1 (en)

Families Citing this family (124)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2004083600A1 (en) * 2003-03-18 2004-09-30 Bj Services Company Method of treating subterranean formations using mixed density proppants or sequential proppant stages
US7207386B2 (en) 2003-06-20 2007-04-24 Bj Services Company Method of hydraulic fracturing to reduce unwanted water production
US7772163B1 (en) 2003-06-20 2010-08-10 Bj Services Company Llc Well treating composite containing organic lightweight material and weight modifying agent
US8167045B2 (en) 2003-08-26 2012-05-01 Halliburton Energy Services, Inc. Methods and compositions for stabilizing formation fines and sand
US7766099B2 (en) 2003-08-26 2010-08-03 Halliburton Energy Services, Inc. Methods of drilling and consolidating subterranean formation particulates
US20050173116A1 (en) 2004-02-10 2005-08-11 Nguyen Philip D. Resin compositions and methods of using resin compositions to control proppant flow-back
US7211547B2 (en) 2004-03-03 2007-05-01 Halliburton Energy Services, Inc. Resin compositions and methods of using such resin compositions in subterranean applications
US7299875B2 (en) 2004-06-08 2007-11-27 Halliburton Energy Services, Inc. Methods for controlling particulate migration
US7726399B2 (en) 2004-09-30 2010-06-01 Bj Services Company Method of enhancing hydraulic fracturing using ultra lightweight proppants
US20060073980A1 (en) * 2004-09-30 2006-04-06 Bj Services Company Well treating composition containing relatively lightweight proppant and acid
US7757768B2 (en) 2004-10-08 2010-07-20 Halliburton Energy Services, Inc. Method and composition for enhancing coverage and displacement of treatment fluids into subterranean formations
US7883740B2 (en) 2004-12-12 2011-02-08 Halliburton Energy Services, Inc. Low-quality particulates and methods of making and using improved low-quality particulates
US7322411B2 (en) * 2005-01-12 2008-01-29 Bj Services Company Method of stimulating oil and gas wells using deformable proppants
US7334635B2 (en) * 2005-01-14 2008-02-26 Halliburton Energy Services, Inc. Methods for fracturing subterranean wells
US7673686B2 (en) 2005-03-29 2010-03-09 Halliburton Energy Services, Inc. Method of stabilizing unconsolidated formation for sand control
US7528096B2 (en) * 2005-05-12 2009-05-05 Bj Services Company Structured composite compositions for treatment of subterranean wells
US7318474B2 (en) 2005-07-11 2008-01-15 Halliburton Energy Services, Inc. Methods and compositions for controlling formation fines and reducing proppant flow-back
US8613320B2 (en) 2006-02-10 2013-12-24 Halliburton Energy Services, Inc. Compositions and applications of resins in treating subterranean formations
US7926591B2 (en) 2006-02-10 2011-04-19 Halliburton Energy Services, Inc. Aqueous-based emulsified consolidating agents suitable for use in drill-in applications
US7819192B2 (en) 2006-02-10 2010-10-26 Halliburton Energy Services, Inc. Consolidating agent emulsions and associated methods
CA2536957C (en) 2006-02-17 2008-01-22 Jade Oilfield Service Ltd. Method of treating a formation using deformable proppants
US7931087B2 (en) * 2006-03-08 2011-04-26 Baker Hughes Incorporated Method of fracturing using lightweight polyamide particulates
US8133587B2 (en) * 2006-07-12 2012-03-13 Georgia-Pacific Chemicals Llc Proppant materials comprising a coating of thermoplastic material, and methods of making and using
US8003214B2 (en) * 2006-07-12 2011-08-23 Georgia-Pacific Chemicals Llc Well treating materials comprising coated proppants, and methods
US7708069B2 (en) * 2006-07-25 2010-05-04 Superior Energy Services, L.L.C. Method to enhance proppant conductivity from hydraulically fractured wells
WO2008092078A1 (en) * 2007-01-26 2008-07-31 Bj Services Company Fracture acidizing method utilizing reactive fluids and deformable particulates
US7699106B2 (en) 2007-02-13 2010-04-20 Bj Services Company Method for reducing fluid loss during hydraulic fracturing or sand control treatment
US7934557B2 (en) 2007-02-15 2011-05-03 Halliburton Energy Services, Inc. Methods of completing wells for controlling water and particulate production
US8058213B2 (en) 2007-05-11 2011-11-15 Georgia-Pacific Chemicals Llc Increasing buoyancy of well treating materials
US7754659B2 (en) 2007-05-15 2010-07-13 Georgia-Pacific Chemicals Llc Reducing flow-back in well treating materials
US8276664B2 (en) * 2007-08-13 2012-10-02 Baker Hughes Incorporated Well treatment operations using spherical cellulosic particulates
US8006760B2 (en) 2008-04-10 2011-08-30 Halliburton Energy Services, Inc. Clean fluid systems for partial monolayer fracturing
US7913762B2 (en) * 2008-07-25 2011-03-29 Baker Hughes Incorporated Method of fracturing using ultra lightweight proppant suspensions and gaseous streams
US9291045B2 (en) * 2008-07-25 2016-03-22 Baker Hughes Incorporated Method of fracturing using ultra lightweight proppant suspensions and gaseous streams
US20100032159A1 (en) * 2008-08-08 2010-02-11 Halliburton Energy Services, Inc. Proppant-containing treatment fluids and methods of use
US8205675B2 (en) * 2008-10-09 2012-06-26 Baker Hughes Incorporated Method of enhancing fracture conductivity
RU2402679C2 (en) * 2008-10-14 2010-10-27 Шлюмберже Текнолоджи Б.В. Method for hydraulic rupture of low-permeable underground bed
US7798227B2 (en) * 2008-12-22 2010-09-21 Bj Services Company Llc Methods for placing multiple stage fractures in wellbores
US7762329B1 (en) 2009-01-27 2010-07-27 Halliburton Energy Services, Inc. Methods for servicing well bores with hardenable resin compositions
US9194223B2 (en) * 2009-12-18 2015-11-24 Baker Hughes Incorporated Method of fracturing subterranean formations with crosslinked fluid
US8371383B2 (en) * 2009-12-18 2013-02-12 Baker Hughes Incorporated Method of fracturing subterranean formations with crosslinked fluid
US9234415B2 (en) 2010-08-25 2016-01-12 Schlumberger Technology Corporation Delivery of particulate material below ground
US8459353B2 (en) 2010-08-25 2013-06-11 Schlumberger Technology Corporation Delivery of particulate material below ground
US8448706B2 (en) 2010-08-25 2013-05-28 Schlumberger Technology Corporation Delivery of particulate material below ground
US8714248B2 (en) 2010-08-25 2014-05-06 Schlumberger Technology Corporation Method of gravel packing
US8607870B2 (en) * 2010-11-19 2013-12-17 Schlumberger Technology Corporation Methods to create high conductivity fractures that connect hydraulic fracture networks in a well
US9328600B2 (en) * 2010-12-03 2016-05-03 Exxonmobil Upstream Research Company Double hydraulic fracturing methods
EP2655795B1 (en) * 2010-12-22 2019-02-20 Maurice B. Dusseault Multi-stage fracture injection process for enhanced resource production from shales
US10001003B2 (en) * 2010-12-22 2018-06-19 Maurice B. Dusseault Multl-stage fracture injection process for enhanced resource production from shales
US20120305247A1 (en) * 2011-06-06 2012-12-06 Yiyan Chen Proppant pillar placement in a fracture with high solid content fluid
US9376901B2 (en) 2011-09-20 2016-06-28 John Pantano Increased resource recovery by inorganic and organic reactions and subsequent physical actions that modify properties of the subterranean formation which reduces produced water waste and increases resource utilization via stimulation of biogenic methane generation
US10041327B2 (en) 2012-06-26 2018-08-07 Baker Hughes, A Ge Company, Llc Diverting systems for use in low temperature well treatment operations
US9920610B2 (en) 2012-06-26 2018-03-20 Baker Hughes, A Ge Company, Llc Method of using diverter and proppant mixture
NL1039260C2 (en) * 2011-12-22 2013-06-26 Resin Proppants Internat B V Method for the preparation of polymer comprising particles.
US9850748B2 (en) * 2012-04-30 2017-12-26 Halliburton Energy Services, Inc. Propping complex fracture networks in tight formations
EP2864441A2 (en) 2012-06-26 2015-04-29 Baker Hughes Incorporated Method of using phthalic and terephthalic acids and derivatives thereof in well treatment operations
US10988678B2 (en) 2012-06-26 2021-04-27 Baker Hughes, A Ge Company, Llc Well treatment operations using diverting system
US11111766B2 (en) 2012-06-26 2021-09-07 Baker Hughes Holdings Llc Methods of improving hydraulic fracture network
CA2877830C (en) 2012-06-26 2018-03-20 Baker Hughes Incorporated Methods of improving hydraulic fracture network
US20140076558A1 (en) * 2012-09-18 2014-03-20 Halliburton Energy Services, Inc. Methods and Compositions for Treating Proppant to Prevent Flow-Back
US10407988B2 (en) 2013-01-29 2019-09-10 Halliburton Energy Services, Inc. Wellbore fluids comprising mineral particles and methods relating thereto
US9353613B2 (en) 2013-02-13 2016-05-31 Halliburton Energy Services, Inc. Distributing a wellbore fluid through a wellbore
US9429006B2 (en) 2013-03-01 2016-08-30 Baker Hughes Incorporated Method of enhancing fracture conductivity
CA2849415C (en) 2013-04-24 2017-02-28 Robert D. Skala Methods for fracturing subterranean formations
GB2527479B (en) * 2013-04-26 2020-10-14 Desbarats Andrew A proppant immobilized enzyme and a viscofied fracture fluid
GB2536516A (en) * 2013-05-21 2016-09-21 Halliburton Energy Services Inc Wellbore fluids comprising mineral particles and methods relating thereto
WO2015021523A1 (en) * 2013-08-15 2015-02-19 Canyon Technical Services Ltd. Method of treating subterranean formations using blended proppants
US9500076B2 (en) * 2013-09-17 2016-11-22 Halliburton Energy Services, Inc. Injection testing a subterranean region
US9574443B2 (en) * 2013-09-17 2017-02-21 Halliburton Energy Services, Inc. Designing an injection treatment for a subterranean region based on stride test data
GB2533048A (en) * 2013-09-17 2016-06-08 Halliburton Energy Services Inc Cyclical diversion techniques in subterranean fracturing operations
US9702247B2 (en) 2013-09-17 2017-07-11 Halliburton Energy Services, Inc. Controlling an injection treatment of a subterranean region based on stride test data
PL3049616T3 (en) 2013-09-26 2019-01-31 Baker Hughes, A Ge Company, Llc Method of optimizing conductivity in a hydraulic fracturing operation
US20160340573A1 (en) * 2014-01-17 2016-11-24 Sergey Vladimirovich Semenov System and methodology for well treatment
US10100626B2 (en) 2014-05-19 2018-10-16 Halliburton Energy Services, Inc. Method of stimulation of brittle rock using a rapid pressure drop
AU2015301423B2 (en) 2014-08-15 2019-01-17 Baker Hughes, A Ge Company, Llc Diverting systems for use in well treatment operations
US10337311B2 (en) 2014-09-03 2019-07-02 Halliburton Energy Services, Inc. Methods of forming variable strength proppant packs
AU2016206998B2 (en) 2015-01-12 2019-11-07 Southwestern Energy Company Novel proppant and methods of using the same
CN104727800B (en) * 2015-01-22 2017-07-25 中国石油集团川庆钻探工程有限公司长庆井下技术作业公司 A kind of temporary stall based on the modified vinal in surface is to fracturing process
CN104727801B (en) * 2015-03-17 2017-12-26 中国石油化工股份有限公司胜利油田分公司石油工程技术研究院 A kind of fracturing technology that big passage is realized using proppant density variation
WO2016164030A1 (en) 2015-04-09 2016-10-13 Halliburton Energy Services, Inc. Fracture having a bottom portion of reduced permeability and a top portion having a higher permeability
US10253250B2 (en) 2015-04-28 2019-04-09 Halliburton Energy Services, Inc. Forming conductive arch channels in subterranean formation fractures
AU2015398683B2 (en) * 2015-06-14 2020-10-22 Halliburton Energy Services, Inc. Fluid creating a fracture having a bottom portion of reduced permeability and a top having a higher permeability
US10577536B2 (en) 2015-06-30 2020-03-03 Halliburton Energy Services, Inc. Vertical proppant suspension in hydraulic fractures
AU2015409638B2 (en) * 2015-09-23 2021-07-08 Halliburton Energy Services, Inc. Enhancing complex fracture geometry in subterranean formations, sequence transport of particulates
CA2997706C (en) 2015-10-15 2020-10-06 Halliburton Energy Services, Inc. Micro-proppant fracturing fluid and slurry concentrate compositions
CA2997709C (en) * 2015-10-22 2020-03-24 Halliburton Energy Services, Inc. Enhancing propped complex fracture networks in subterranean formations
US9896619B2 (en) * 2015-12-08 2018-02-20 Halliburton Energy Services, Inc. Enhancing conductivity of microfractures
US9995125B2 (en) 2016-03-21 2018-06-12 Halliburton Energy Services, Inc. Fracture network model for simulating treatment of subterranean formations
US10370950B2 (en) 2016-05-21 2019-08-06 Baker Hughes, A Ge Company, Llc Method of enhancing conductivity from post frac channel formation
CA3024784C (en) * 2016-06-23 2021-06-08 Halliburton Energy Services, Inc. Proppant-free channels in a propped fracture using ultra-low density, degradable particulates
US11230660B2 (en) * 2016-07-08 2022-01-25 Halliburton Energy Services, Inc. Lightweight micro-proppant
CA3027352C (en) * 2016-07-22 2022-05-10 Halliburton Energy Services, Inc. Liquid gas treatment fluids for use in subterranean formation operations
WO2018022114A1 (en) 2016-07-29 2018-02-01 Halliburton Energy Services, Inc. Time-dependent spatial distribution of multiple proppant types or sizes in a fracture network
US10738583B2 (en) * 2016-08-21 2020-08-11 Battelle Memorial Institute Multi-component solid epoxy proppant binder resins
US10612356B2 (en) 2017-03-01 2020-04-07 Proptester, Inc. Fracture fluid and proppant transport testing systems and methods of using same
US11365626B2 (en) 2017-03-01 2022-06-21 Proptester, Inc. Fluid flow testing apparatus and methods
US10422209B2 (en) 2018-01-09 2019-09-24 Saudi Arabian Oil Company Magnetic proppants for enhanced fracturing
CN108843296B (en) * 2018-06-25 2021-05-18 成都北方石油勘探开发技术有限公司 Single-well repeated fracturing effect prediction method based on multi-factor influence
US11313214B2 (en) 2018-08-10 2022-04-26 Halliburton Energy Services, Inc. Creating high conductivity layers in propped formations
US10647910B1 (en) 2018-10-19 2020-05-12 Halliburton Energy Services, Inc. Methods for enhancing effective propped fracture conductivity
US11441406B2 (en) 2018-12-21 2022-09-13 Halliburton Energy Services, Inc. Forming frac packs in high permeability formations
US10808515B1 (en) 2019-06-10 2020-10-20 Halliburton Energy Services, Inc. Propped fracture geometry with continuous flow
US10989035B2 (en) 2019-06-20 2021-04-27 Halliburton Energy Services, Inc. Proppant ramp-up for cluster efficiency
US10920558B2 (en) 2019-07-12 2021-02-16 Halliburton Energy Services, Inc. Method of enhancing proppant distribution and well production
US11492541B2 (en) 2019-07-24 2022-11-08 Saudi Arabian Oil Company Organic salts of oxidizing anions as energetic materials
WO2021016515A1 (en) 2019-07-24 2021-01-28 Saudi Arabian Oil Company Oxidizing gasses for carbon dioxide-based fracturing fluids
US11319790B2 (en) 2019-10-30 2022-05-03 Halliburton Energy Services, Inc. Proppant ramp up decision making
WO2021138355A1 (en) 2019-12-31 2021-07-08 Saudi Arabian Oil Company Viscoelastic-surfactant fracturing fluids having oxidizer
US11352548B2 (en) 2019-12-31 2022-06-07 Saudi Arabian Oil Company Viscoelastic-surfactant treatment fluids having oxidizer
US11339321B2 (en) 2019-12-31 2022-05-24 Saudi Arabian Oil Company Reactive hydraulic fracturing fluid
US11268373B2 (en) 2020-01-17 2022-03-08 Saudi Arabian Oil Company Estimating natural fracture properties based on production from hydraulically fractured wells
US11473001B2 (en) 2020-01-17 2022-10-18 Saudi Arabian Oil Company Delivery of halogens to a subterranean formation
US11473009B2 (en) 2020-01-17 2022-10-18 Saudi Arabian Oil Company Delivery of halogens to a subterranean formation
US11365344B2 (en) 2020-01-17 2022-06-21 Saudi Arabian Oil Company Delivery of halogens to a subterranean formation
US11143008B1 (en) 2020-04-24 2021-10-12 Saudi Arabian Oil Company Methods of hydraulic fracturing
US11578263B2 (en) 2020-05-12 2023-02-14 Saudi Arabian Oil Company Ceramic-coated proppant
US11795382B2 (en) 2020-07-14 2023-10-24 Saudi Arabian Oil Company Pillar fracturing
US11542815B2 (en) 2020-11-30 2023-01-03 Saudi Arabian Oil Company Determining effect of oxidative hydraulic fracturing
US11867028B2 (en) 2021-01-06 2024-01-09 Saudi Arabian Oil Company Gauge cutter and sampler apparatus
US11585176B2 (en) 2021-03-23 2023-02-21 Saudi Arabian Oil Company Sealing cracked cement in a wellbore casing
US11867012B2 (en) 2021-12-06 2024-01-09 Saudi Arabian Oil Company Gauge cutter and sampler apparatus
US11629284B1 (en) * 2021-12-17 2023-04-18 Saudi Arabian Oil Company Efficient stimulation of formation using micro-proppants
US11702588B1 (en) * 2021-12-17 2023-07-18 Saudi Arabian Oil Company Efficient stimulation from carbonate reservoirs using micro-proppants
US11739616B1 (en) 2022-06-02 2023-08-29 Saudi Arabian Oil Company Forming perforation tunnels in a subterranean formation

Family Cites Families (146)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US2596843A (en) 1949-12-31 1952-05-13 Stanolind Oil & Gas Co Fracturing formations in wells
US2966457A (en) 1956-05-08 1960-12-27 Swift & Co Gelled fracturing fluids
US3151678A (en) 1958-09-02 1964-10-06 Dow Chemical Co Method of fracturing formations
US3159217A (en) 1959-04-10 1964-12-01 Dow Chemical Co Plastically deformable solids in treating subterranean formations
US3089542A (en) 1960-04-13 1963-05-14 American Cyanamid Co Oil well fracturing method
US3127937A (en) 1960-08-22 1964-04-07 Atlantic Refining Co Method and a composition for treating subsurface fractures
US3149674A (en) 1961-08-23 1964-09-22 Jersey Prod Res Co Fracturing of subsurface earth formations
US3149673A (en) 1961-08-23 1964-09-22 Jersey Prod Res Co Use of solid polyolefin propping agent in hydraulic fracturing
US3175615A (en) 1962-10-29 1965-03-30 Jersey Prod Res Co Fracturing of subsurface earth formations
US3254717A (en) 1962-11-19 1966-06-07 Gulf Research Development Co Fracturing process and impregnated propping agent for use therein
US3335797A (en) 1963-12-18 1967-08-15 Dow Chemical Co Controlling fractures during well treatment
US3266573A (en) 1964-03-25 1966-08-16 Pan American Petroleum Corp Method of fracturing subsurface formations
US3492147A (en) 1964-10-22 1970-01-27 Halliburton Co Method of coating particulate solids with an infusible resin
US3335796A (en) 1965-02-12 1967-08-15 Chevron Res Treatment of wells with resin-impregnated, resin-coated walnut shell particles
US3372752A (en) 1966-04-22 1968-03-12 Dow Chemical Co Hydraulic fracturing
US3399727A (en) 1966-09-16 1968-09-03 Exxon Production Research Co Method for propping a fracture
US3497008A (en) 1968-03-05 1970-02-24 Exxon Production Research Co Method of propping fractures with ceramic particles
US3659651A (en) 1970-08-17 1972-05-02 Exxon Production Research Co Hydraulic fracturing using reinforced resin pellets
US3709300A (en) 1971-08-27 1973-01-09 Union Oil Co Hydraulic fracturing process
US3888311A (en) 1973-10-01 1975-06-10 Exxon Production Research Co Hydraulic fracturing method
US4051900A (en) 1974-06-13 1977-10-04 Dale Hankins Propping material for hydraulic fracturing
US3929191A (en) 1974-08-15 1975-12-30 Exxon Production Research Co Method for treating subterranean formations
US3954142A (en) 1974-08-21 1976-05-04 Halliburton Company Zonal fracture treatment of well formations
US3937283A (en) 1974-10-17 1976-02-10 The Dow Chemical Company Formation fracturing with stable foam
US4060988A (en) 1975-04-21 1977-12-06 Texaco Inc. Process for heating a fluid in a geothermal formation
US4074760A (en) 1976-11-01 1978-02-21 The Dow Chemical Company Method for forming a consolidated gravel pack
US4078609A (en) * 1977-03-28 1978-03-14 The Dow Chemical Company Method of fracturing a subterranean formation
US4195010A (en) 1977-07-06 1980-03-25 Burns & Russell Company of Baltimore City Ceramic coated quartz particles
US4216829A (en) 1977-10-06 1980-08-12 Halliburton Company Gelled water epoxy sand consolidation system
US4421167A (en) 1980-11-05 1983-12-20 Exxon Production Research Co. Method of controlling displacement of propping agent in fracturing treatments
US4547468A (en) 1981-08-10 1985-10-15 Terra Tek, Inc. Hollow proppants and a process for their manufacture
US4439489A (en) 1982-02-16 1984-03-27 Acme Resin Corporation Particles covered with a cured infusible thermoset film and process for their production
US4462466A (en) 1982-03-29 1984-07-31 Kachnik Joseph E Method of propping fractures in subterranean formations
US4502967A (en) 1982-09-27 1985-03-05 Halliburton Company Method and compositions for fracturing subterranean formations
US4509598A (en) 1983-03-25 1985-04-09 The Dow Chemical Company Fracturing fluids containing bouyant inorganic diverting agent and method of use in hydraulic fracturing of subterranean formations
US4506734A (en) 1983-09-07 1985-03-26 The Standard Oil Company Fracturing fluid breaker system which is activated by fracture closure
US4493875A (en) 1983-12-09 1985-01-15 Minnesota Mining And Manufacturing Company Proppant for well fractures and method of making same
US4680230A (en) 1984-01-18 1987-07-14 Minnesota Mining And Manufacturing Company Particulate ceramic useful as a proppant
US4585064A (en) 1984-07-02 1986-04-29 Graham John W High strength particulates
US4717594A (en) 1984-07-02 1988-01-05 Graham John W High strength particulates
US4888240A (en) 1984-07-02 1989-12-19 Graham John W High strength particulates
US4632876A (en) 1985-06-12 1986-12-30 Minnesota Mining And Manufacturing Company Ceramic spheroids having low density and high crush resistance
US4654266A (en) 1985-12-24 1987-03-31 Kachnik Joseph L Durable, high-strength proppant and method for forming same
US4830794A (en) 1986-05-19 1989-05-16 Halliburton Company Dry sand foam generator
US4733729A (en) 1986-09-08 1988-03-29 Dowell Schlumberger Incorporated Matched particle/liquid density well packing technique
US4840729A (en) 1987-01-02 1989-06-20 Atlantic Richfield Company Oil spill recovery apparatus
US4850430A (en) 1987-02-04 1989-07-25 Dowell Schlumberger Incorporated Matched particle/liquid density well packing technique
US4796701A (en) 1987-07-30 1989-01-10 Dowell Schlumberger Incorporated Pyrolytic carbon coating of media improves gravel packing and fracturing capabilities
US4923714A (en) 1987-09-17 1990-05-08 Minnesota Mining And Manufacturing Company Novolac coated ceramic particulate
US4869960A (en) 1987-09-17 1989-09-26 Minnesota Mining And Manufacturing Company Epoxy novolac coated ceramic particulate
US4829100A (en) 1987-10-23 1989-05-09 Halliburton Company Continuously forming and transporting consolidatable resin coated particulate materials in aqueous gels
DE3868402D1 (en) 1988-05-13 1992-03-26 Sarea Ag USE OF A COMPOSITION FOR THE SURFACE TREATMENT OF SOILS.
US4921821A (en) * 1988-08-02 1990-05-01 Norton-Alcoa Proppants Lightweight oil and gas well proppants and methods for making and using same
US4921820A (en) 1989-01-17 1990-05-01 Norton-Alcoa Proppants Lightweight proppant for oil and gas wells and methods for making and using same
US4875525A (en) 1989-03-03 1989-10-24 Atlantic Richfield Company Consolidated proppant pack for producing formations
US4887670A (en) 1989-04-05 1989-12-19 Halliburton Company Controlling fracture growth
US4969523A (en) 1989-06-12 1990-11-13 Dowell Schlumberger Incorporated Method for gravel packing a well
US5069283A (en) 1989-08-02 1991-12-03 The Western Company Of North America Fracturing process using carbon dioxide and nitrogen
US5074359A (en) 1989-11-06 1991-12-24 Atlantic Richfield Company Method for hydraulic fracturing cased wellbores
US5175133A (en) 1989-12-22 1992-12-29 Comalco Aluminium Limited Ceramic microspheres
US5240654A (en) 1989-12-22 1993-08-31 Comalco Aluminium Limited Method of making ceramic microspheres
US5103905A (en) 1990-05-03 1992-04-14 Dowell Schlumberger Incorporated Method of optimizing the conductivity of a propped fractured formation
US5305832A (en) 1992-12-21 1994-04-26 The Western Company Of North America Method for fracturing high temperature subterranean formations
US5330005A (en) 1993-04-05 1994-07-19 Dowell Schlumberger Incorporated Control of particulate flowback in subterranean wells
CA2497728C (en) 1993-04-05 2008-02-19 Roger J. Card Control of particulate flowback in subterranean wells
US5422183A (en) 1993-06-01 1995-06-06 Santrol, Inc. Composite and reinforced coatings on proppants and particles
US5425421A (en) 1993-10-05 1995-06-20 Atlantic Richfield Company Method for sealing unwanted fractures in fluid-producing earth formations
US5381864A (en) 1993-11-12 1995-01-17 Halliburton Company Well treating methods using particulate blends
US5447197A (en) 1994-01-25 1995-09-05 Bj Services Company Storable liquid cementitious slurries for cementing oil and gas wells
US5837656A (en) 1994-07-21 1998-11-17 Santrol, Inc. Well treatment fluid compatible self-consolidating particles
US5531274A (en) 1994-07-29 1996-07-02 Bienvenu, Jr.; Raymond L. Lightweight proppants and their use in hydraulic fracturing
CA2129613C (en) 1994-08-05 1997-09-23 Samuel Luk High proppant concentration/high co2 ratio fracturing system
US5435391A (en) 1994-08-05 1995-07-25 Mobil Oil Corporation Method for fracturing and propping a formation
GB9503949D0 (en) 1995-02-28 1995-04-19 Atomic Energy Authority Uk Oil well treatment
US5639806A (en) 1995-03-28 1997-06-17 Borden Chemical, Inc. Bisphenol-containing resin coating articles and methods of using same
US5582249A (en) 1995-08-02 1996-12-10 Halliburton Company Control of particulate flowback in subterranean wells
US5960878A (en) 1995-03-29 1999-10-05 Halliburton Energy Services, Inc. Methods of protecting well tubular goods from corrosion
US6047772A (en) 1995-03-29 2000-04-11 Halliburton Energy Services, Inc. Control of particulate flowback in subterranean wells
US6209643B1 (en) 1995-03-29 2001-04-03 Halliburton Energy Services, Inc. Method of controlling particulate flowback in subterranean wells and introducing treatment chemicals
US5604184A (en) 1995-04-10 1997-02-18 Texaco, Inc. Chemically inert resin coated proppant system for control of proppant flowback in hydraulically fractured wells
US6528157B1 (en) 1995-11-01 2003-03-04 Borden Chemical, Inc. Proppants with fiber reinforced resin coatings
US5582250A (en) * 1995-11-09 1996-12-10 Dowell, A Division Of Schlumberger Technology Corporation Overbalanced perforating and fracturing process using low-density, neutrally buoyant proppant
US5699860A (en) 1996-02-22 1997-12-23 Halliburton Energy Services, Inc. Fracture propping agents and methods
US5799734A (en) 1996-07-18 1998-09-01 Halliburton Energy Services, Inc. Method of forming and using particulate slurries for well completion
US5950727A (en) 1996-08-20 1999-09-14 Irani; Cyrus A. Method for plugging gas migration channels in the cement annulus of a wellbore using high viscosity polymers
US6364018B1 (en) 1996-11-27 2002-04-02 Bj Services Company Lightweight methods and compositions for well treating
US7426961B2 (en) 2002-09-03 2008-09-23 Bj Services Company Method of treating subterranean formations with porous particulate materials
US6059034A (en) 1996-11-27 2000-05-09 Bj Services Company Formation treatment method using deformable particles
US6330916B1 (en) 1996-11-27 2001-12-18 Bj Services Company Formation treatment method using deformable particles
US6772838B2 (en) * 1996-11-27 2004-08-10 Bj Services Company Lightweight particulate materials and uses therefor
US6749025B1 (en) 1996-11-27 2004-06-15 Bj Services Company Lightweight methods and compositions for sand control
DK133397A (en) 1996-11-27 1998-05-28 B J Services Company Method of treating formations using deformable particles
US5964289A (en) 1997-01-14 1999-10-12 Hill; Gilman A. Multiple zone well completion method and apparatus
US6169058B1 (en) 1997-06-05 2001-01-02 Bj Services Company Compositions and methods for hydraulic fracturing
US5924488A (en) 1997-06-11 1999-07-20 Halliburton Energy Services, Inc. Methods of preventing well fracture proppant flow-back
US5908073A (en) 1997-06-26 1999-06-01 Halliburton Energy Services, Inc. Preventing well fracture proppant flow-back
US5921317A (en) 1997-08-14 1999-07-13 Halliburton Energy Services, Inc. Coating well proppant with hardenable resin-fiber composites
US6451953B1 (en) 1997-12-18 2002-09-17 Sun Drilling Products, Corp. Chain entanglement crosslinked polymers
EP0933498B1 (en) 1998-02-03 2003-05-28 Halliburton Energy Services, Inc. Method of rapidly consolidating particulate materials in wells
US6211120B1 (en) 1998-02-11 2001-04-03 Baker Hughes Incorporated Application of aluminum chlorohydrate in viscosifying brine for carrying proppants in gravel packing
US6070666A (en) 1998-04-30 2000-06-06 Atlantic Richfield Company Fracturing method for horizontal wells
US6114410A (en) 1998-07-17 2000-09-05 Technisand, Inc. Proppant containing bondable particles and removable particles
DK1023382T3 (en) 1998-07-22 2006-06-26 Hexion Specialty Chemicals Inc Composite propellant, composite filtration agents and processes for their preparation and use
US6582819B2 (en) * 1998-07-22 2003-06-24 Borden Chemical, Inc. Low density composite proppant, filtration media, gravel packing media, and sports field media, and methods for making and using same
US6406789B1 (en) 1998-07-22 2002-06-18 Borden Chemical, Inc. Composite proppant, composite filtration media and methods for making and using same
AU5690099A (en) 1998-08-24 2000-03-14 Sun Drilling Products Corporation Free radical inhibitors for quenching aqueous phase polymer growth and related methods
US6116342A (en) 1998-10-20 2000-09-12 Halliburton Energy Services, Inc. Methods of preventing well fracture proppant flow-back
US6138760A (en) 1998-12-07 2000-10-31 Bj Services Company Pre-treatment methods for polymer-containing fluids
US6194355B1 (en) 1999-02-09 2001-02-27 Baker Hughes Incorporated Use of alkoxylated surfactants and aluminum chlorohydrate to improve brine-based drilling fluids
US6315041B1 (en) 1999-04-15 2001-11-13 Stephen L. Carlisle Multi-zone isolation tool and method of stimulating and testing a subterranean well
US6640897B1 (en) 1999-09-10 2003-11-04 Bj Services Company Method and apparatus for through tubing gravel packing, cleaning and lifting
CA2318703A1 (en) 1999-09-16 2001-03-16 Bj Services Company Compositions and methods for cementing using elastic particles
US6311773B1 (en) 2000-01-28 2001-11-06 Halliburton Energy Services, Inc. Resin composition and methods of consolidating particulate solids in wells with or without closure pressure
CA2401023A1 (en) 2000-03-06 2001-09-13 Harold D. Brannon Lightweight compositions and methods for sand control
DE60120553T2 (en) 2000-04-28 2007-06-06 Ricoh Co., Ltd. Toner, external additive, and imaging process
US6439310B1 (en) 2000-09-15 2002-08-27 Scott, Iii George L. Real-time reservoir fracturing process
US6372678B1 (en) 2000-09-28 2002-04-16 Fairmount Minerals, Ltd Proppant composition for gas and oil well fracturing
US6444162B1 (en) 2000-11-27 2002-09-03 The United States Of America As Represented By The United States Department Of Energy Open-cell glass crystalline porous material
US6439309B1 (en) 2000-12-13 2002-08-27 Bj Services Company Compositions and methods for controlling particulate movement in wellbores and subterranean formations
US7226971B2 (en) 2000-12-22 2007-06-05 Basf Corporation Polyester resin with carbamate functionality, a method of preparing the resin, and a coating composition utilizing the resin
CA2329834A1 (en) 2000-12-28 2002-06-28 David Droppert High strength, heat- and corrosion-resistant ceramic granules for proppants
US6579947B2 (en) 2001-02-20 2003-06-17 Rhodia Chimie Hydraulic fracturing fluid comprising a block copolymer containing at least one water-soluble block and one hydrophobic block
US7001872B2 (en) 2001-06-11 2006-02-21 Halliburton Energy Services, Inc. Subterranean formation treating fluid and methods of fracturing subterranean formations
US6766817B2 (en) 2001-07-25 2004-07-27 Tubarc Technologies, Llc Fluid conduction utilizing a reversible unsaturated siphon with tubarc porosity action
US6725931B2 (en) 2002-06-26 2004-04-27 Halliburton Energy Services, Inc. Methods of consolidating proppant and controlling fines in wells
US6830105B2 (en) 2002-03-26 2004-12-14 Halliburton Energy Services, Inc. Proppant flowback control using elastomeric component
AU2003240679A1 (en) 2002-05-21 2003-12-02 Sofitech N.V. Hydraulic fracturing method
EP1531984A4 (en) 2002-05-31 2005-12-14 Sun Drilling Products Corp Low density polymer beads
US7153575B2 (en) 2002-06-03 2006-12-26 Borden Chemical, Inc. Particulate material having multiple curable coatings and methods for making and using same
US6776235B1 (en) * 2002-07-23 2004-08-17 Schlumberger Technology Corporation Hydraulic fracturing method
US20040023818A1 (en) 2002-08-05 2004-02-05 Nguyen Philip D. Method and product for enhancing the clean-up of hydrocarbon-producing well
US6705400B1 (en) 2002-08-28 2004-03-16 Halliburton Energy Services, Inc. Methods and compositions for forming subterranean fractures containing resilient proppant packs
US6742590B1 (en) 2002-09-05 2004-06-01 Halliburton Energy Services, Inc. Methods of treating subterranean formations using solid particles and other larger solid materials
US7036591B2 (en) 2002-10-10 2006-05-02 Carbo Ceramics Inc. Low density proppant
US6892813B2 (en) 2003-01-30 2005-05-17 Halliburton Energy Services, Inc. Methods for preventing fracture proppant flowback
WO2004083600A1 (en) * 2003-03-18 2004-09-30 Bj Services Company Method of treating subterranean formations using mixed density proppants or sequential proppant stages
BRPI0409410A (en) 2003-04-15 2006-04-25 Hexion Specialty Chemicals Inc particulate material containing thermoplastic elastomer and methods for its manufacture and use
US20040244978A1 (en) 2003-06-04 2004-12-09 Sun Drilling Products Corporation Lost circulation material blend offering high fluid loss with minimum solids
US7207386B2 (en) 2003-06-20 2007-04-24 Bj Services Company Method of hydraulic fracturing to reduce unwanted water production
US7066258B2 (en) 2003-07-08 2006-06-27 Halliburton Energy Services, Inc. Reduced-density proppants and methods of using reduced-density proppants to enhance their transport in well bores and fractures
US7086460B2 (en) 2003-07-14 2006-08-08 Halliburton Energy Services, Inc. In-situ filters, method of forming same and systems for controlling proppant flowback employing same
US20050028976A1 (en) 2003-08-05 2005-02-10 Nguyen Philip D. Compositions and methods for controlling the release of chemicals placed on particulates
US7036597B2 (en) 2003-08-28 2006-05-02 Halliburton Energy Services, Inc. Systems and methods for treating a subterranean formation using carbon dioxide and a crosslinked fracturing fluid
US20050089631A1 (en) 2003-10-22 2005-04-28 Nguyen Philip D. Methods for reducing particulate density and methods of using reduced-density particulates
US7036590B2 (en) 2004-02-13 2006-05-02 Halliburton Energy Services, Inc. Two stage subterranean zone fracturing fluids and methods
MXPA06011762A (en) 2004-04-12 2007-04-13 Carbo Ceramics Inc Coating and/or treating hydraulic fracturing proppants to improve wettability, proppant lubrication, and/or to reduce damage by fracturing fluids and reservoir fluids.

Also Published As

Publication number Publication date
CA2519144C (en) 2008-12-23
US8127850B2 (en) 2012-03-06
US7472751B2 (en) 2009-01-06
US20080032898A1 (en) 2008-02-07
US7210528B1 (en) 2007-05-01
CA2644213A1 (en) 2004-09-30
US20090107674A1 (en) 2009-04-30
US20110180260A1 (en) 2011-07-28
WO2004083600A1 (en) 2004-09-30
CA2519144A1 (en) 2004-09-30
US7918277B2 (en) 2011-04-05

Similar Documents

Publication Publication Date Title
CA2644213C (en) Method of treating subterranean formations using mixed density proppants or sequential proppant stages
US7726399B2 (en) Method of enhancing hydraulic fracturing using ultra lightweight proppants
US10696897B2 (en) Sand control method using deformable non-spherical particulates
CA2471559C (en) Improved method of hydraulic fracturing to reduce unwanted water production
CA2923232C (en) Method of optimizing conductivity in a hydraulic fracturing operation
US8127849B2 (en) Method of using lightweight polyamides in hydraulic fracturing and sand control operations
CA2784390A1 (en) Method of fracturing multiple zones within a well using propellant pre-fracturing
CA3031541C (en) Method of enhancing fracture complexity using far-field divert systems
CA2795417C (en) Method of treating subterranean formations using mixed density proppants or sequential proppant stages
WO2015021523A1 (en) Method of treating subterranean formations using blended proppants

Legal Events

Date Code Title Description
EEER Examination request