WO2016133895A1

WO2016133895A1 - Well treatment

Info

Publication number: WO2016133895A1
Application number: PCT/US2016/018054
Authority: WO
Inventors: Courtney PAYNE; Murtaza Ziauddin; Mohan Kanaka Raju PANGA; Camille MEZA
Original assignee: Schlumberger Canada Ltd; Services Petroliers Schlumberger SA; Schlumberger Technology BV; Schlumberger Technology Corp
Current assignee: Schlumberger Canada Ltd; Services Petroliers Schlumberger SA; Schlumberger Technology BV; Schlumberger Technology Corp
Priority date: 2015-02-16
Filing date: 2016-02-16
Publication date: 2016-08-25
Anticipated expiration: 2017-08-16

Abstract

Methods for treating a subterranean formation penetrated by a wellbore include forming a mixture of a fluorine generating source and a carrier fluid, where the fluorine generating source includes at least hydrogen fluoride and a copolymer having ionizable functional groups of the copolymer associated with the hydrogen fluoride; and the carrier fluid can include a component selected from the group consisting of water, a viscosifier, an alcohol, a salt, an acid, a surfactant, and combinations thereof. The subterranean formation is then contacted with the mixture.

Description

WELL TREATMENT

RELATED APPLICATION INFORMATION

[0001] This Patent Document claims priority under 35 U.S.C. § 120 to U.S. Provisional Patent Application No. 62/1 16693 filed February 16, 2015, the disclosure of which is incorporated by reference herein in its entirety.

FI ELD

[0002] The field to which the disclosure generally relates to is methods of using fluids in a wellbore penetrating a subterranean formation operations, and in particular, generating hydrofluoric acid in a subterranean formation for treating the formation.

BACKGROUND

[0003] This section provides background information to facilitate a better understanding of the various aspects of the disclosure. It should be understood that the statements in this section of this document are to be read in this light, and not as admissions of prior art.

[0004] Hydrocarbons (oil, condensate, and gas) are produced from wellbores drilled into the subterranean formations containing them. For a variety of reasons, such as inherently low permeability of the reservoirs, depletion, scaling or damage to the formation caused by drilling and completion of the wellbore, the flow, or otherwise production, of hydrocarbons into the wellbore may, in some cases, be undesirably low. In order to achieve desired flow levels, the wellbore may be "stimulated" by, for example, hydraulic fracturing techniques, chemical (such as acid) stimulation techniques, or a combination of the two techniques (commonly referred to as acid fracturing or fracture acidizing).

[0005] Among the methods of stimulating a subterranean formation, to increase the production of oil or gas or for siliceous scale removal in a well or gravel pack, is the use of acid in an acidizing treatment. One of the most commonly used acids for the dissolution of siliceous materials in a well is hydrofluoric acid. The acid can be added directly to a solution to be pumped into the formation, or generated downhole using a fluorine containing precursor. In the first case, aqueous hydrofluoric acid may be dangerous to handle due to the inherent hazards of the acid solution itself. Additionally, above certain concentrations hydrofluoric acid produces toxic vapors. Therefore a number of precautions should be taken when transporting or handling hydrofluoric acid.

[0006] To reduce the risks of handling hydrofluoric acid directly, a fluorine containing precursor has been commonly employed. These compounds generate hydrofluoric acid when mixed with a mineral or organic acid. The precursors used are often ammonium fluoride salts, which have less severe and immediate dangers than the related acid. However, solids such as ammonium fluoride salts are more difficult to mix on site and increase the risk of exposure to fluorine when mixing.

[0007] Therefore there is a need to develop solutions which provide safer forms of generating hydrofluoric acid for treating a subterranean formations, which provide sufficient properties to siliceous formations, such need, met at least in part, by the following disclosure.

SUMMARY

[0008] This section provides a general summary of the disclosure, and is not necessarily a comprehensive disclosure of its full scope or all of its features.

[0009] In aspects according to the disclosure, methods of treating a subterranean formation penetrated by a well bore are disclosed. The methods provide a treatment fluid including a carrier fluid and a fluorine generating source made of at least hydrogen fluoride and a polymer. In further aspects, methods of treating a subterranean formation penetrated by a wellbore are disclosed where the wellbore is be drilled through siliceous subterranean formation, a mixture of a carrier fluid and a fluorine generating source containing hydrogen fluoride and a polymer is prepared, and the mixture is injected into the wellbore to treat the siliceous subterranean formation.

[0010] Some composition embodiments of the disclosure include a fluorine generating source containing at least hydrogen fluoride and a copolymer with ionizable functional groups ionically associated with the hydrogen fluoride, and a carrier fluid. The carrier fluid can contain a component selected from the group consisting of water, a viscosifier, an alcohol, a salt, an acid, a surfactant, and combinations thereof. The fluorine generating source may be provided in a liquid, solid, or semi-solid form. In some cases, the copolymer is polyacrylate/polyacrylamide cross-linked copolymer. The copolymer may also be a cross-linked copolymer comprised of water soluble polymers selected from the group consisting of cellulose ethers, modified starches, starch derivatives, natural gum derivatives, polyacrylic acid salts, ethylene oxide polymer, methacrylic acid polymer, polyethyleneimine polymer, polyvinyl pyrrolidone polymer, polylactic acid, polymaleic acid, polymethacrylic acid and mixtures thereof. The copolymers may have any suitable molecular weight, and in some instances, the molecular weight is from about 1 ,000 to about 10,000,000.

[0011] In some other embodiments of the disclosure, methods for treating a subterranean formation penetrated by a wellbore are provided, the methods including forming a mixture of a fluorine generating source and a carrier fluid, the fluorine generating source containing hydrogen fluoride and a copolymer having ionizable functional groups ionically associated with the hydrogen fluoride, and the carrier fluid. The carrier fluid can contain a component selected from the group consisting of water, a viscosifier, an alcohol, a salt, an acid, a surfactant, and combinations thereof The subterranean formation is then contacted with the mixture. The mixture may be prepared at the surface in mixing equipment adjacent the wellbore, or in some other cases, the mixture is formed in the wellbore. When formed in the wellbore, the fluorine generating source or the carrier fluid are delivered into the wellbore through a coiled tubing.

[0012] In some aspects a fracture is formed in the subterranean formation, the fluorine generating source is placed in the fracture, and hydrogen fluoride is released after the fluorine generating source is placed in the fracture. In some cases, the mixture further includes a proppant, and the proppant is placed in the fracture with the fluorine generating source. The fluorine generating source may also be capable of propping open the fracture until the hydrogen fluoride is released. [0013] In other embodiments according to the disclosure, methods include forming a mixture of a fluorine generating source and a carrier fluid, the fluorine generating source comprising hydrogen fluoride and a copolymer having ionizable functional groups ionically associated with the hydrogen fluoride, and the carrier fluid. The carrier fluid can contain a component selected from the group consisting of water, a viscosifier, an alcohol, a salt, an acid, a surfactant, and combinations thereof The mixture is injected into a wellbore penetrating a subterranean formation at a pressure equal to or below the fracture initiation pressure of the subterranean formation, and the fluorine generating source releases hydrogen fluoride to dissolve siliceous scale in tubulars, treat a geothermal well, treat a thermal oil recovery well, or matrix acidize a siliceous formation.

BRIEF DESCRIPTION OF THE DRAWINGS

[0014] FIG. 1 depicts illustrative data showing silicon concentrations over time for Solutions A - D contacted with silica flour, as described in the examples herein.

[0015] FIG. 2 depicts illustrative data showing silicon concentrations over time for Solutions D and E contacted with kaolinite, as described in the examples herein.

[0016] FIG. 3 depicts illustrative data showing aluminum concentrations over time for Solutions D and E contacted with kaolinite, as described in the examples herein.

[0017] FIG. 4 depicts illustrative data showing silicon concentrations over time for Solutions D and E contacted with kaolinite, as described in the examples herein.

[0018] FIG. 5 depicts illustrative data showing aluminum concentrations over time for Solutions D and E contacted with kaolinite, as described in the examples herein.

DETAI LED DESCRIPTION

[0019] At the outset, it should be noted that in the development of any actual embodiments, numerous implementation-specific decisions must be made to achieve the developer's specific goals, such as compliance with system and business related constraints, which can vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time consuming but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure.

[0020] The description and examples are presented solely for the purpose of illustrating some embodiments and should not be construed as a limitation to the scope and applicability. In the summary and this detailed description, each numerical value should be read once as modified by the term "about" (unless already expressly so modified), and then read again as not so modified unless otherwise indicated in context. Also, in the summary and this detailed description, it should be understood that a concentration range listed or described as being useful, suitable, or the like, is intended that any and every concentration within the range, including the end points, is to be considered as having been stated. For example, "a range of from 1 to 10" is to be read as indicating each and every possible number along the continuum between about 1 and about 10. Thus, even if specific data points within the range, or even no data points within the range, are explicitly identified or refer to only a few specific, it is to be understood that inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that inventors possession of the entire range and all points within the range disclosed and enabled the entire range and all points within the range.

[0021] Unless expressly stated to the contrary, "or" refers to an inclusive or and not to an exclusive or. For example, a condition A or B is satisfied by anyone of the following: A is true (or present) and B is false (or not present), A is false (or not present) and B is true (or present), and both A and B are true (or present).

[0022] In addition, use of the "a" or "an" are employed to describe elements and components of the embodiments herein. This is done merely for convenience and to give a general sense of concepts according to the disclosure. This description should be read to include one or at least one and the singular also includes the plural unless otherwise stated. [0023] The terminology and phraseology used herein is for descriptive purposes and should not be construed as limiting in scope. Language such as "including," "comprising," "having," "containing," or "involving," and variations thereof, is intended to be broad and encompass the subject matter listed thereafter, equivalents, and additional subject matter not recited.

[0024] Also, as used herein any references to "one embodiment" or "an embodiment" means that a particular element, feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment. The appearances of the phrase "in one embodiment" in various places in the specification are not necessarily referring to the same embodiment.

[0025] The following definitions are provided in order to aid those skilled in the art in understanding the detailed description.

[0026] The term "treatment", or "treating", refers to any subterranean operation that uses a fluid in conjunction with a desired function and/or for a desired purpose. The term "treatment", or "treating", does not imply any particular action by the fluid.

[0027] The term formation as utilized herein should be understood broadly. A formation includes any underground fluidly porous formation, and can include without limitation any oil, gas, condensate, mixed hydrocarbons, paraffin, kerogen, water, and/or CO2 accepting or providing formations. A formation can be fluidly coupled to a wellbore, which may be an injector well, a producer well, and/or a fluid storage well. The wellbore may penetrate the formation vertically, horizontally, in a deviated orientation, or combinations of these. The formation may include any geology, including at least a sandstone, limestone, dolomite, shale, tar sand, and/or unconsolidated formation. The wellbore may be an individual wellbore and/or a part of a set of wellbores directionally deviated from a number of close proximity surface wellbores (e.g. off a pad or rig) or single initiating wellbore that divides into multiple wellbores below the surface.

[0028] The term "oilfield treatment fluid" as utilized herein should be understood broadly. In certain embodiments, an oilfield treatment fluid includes any fluid having utility in an oilfield type application, including a gas, oil, geothermal, or injector well. In certain embodiments, an oilfield treatment fluid includes any fluid having utility in any formation or wellbore described herein. In certain embodiments, an oilfield treatment fluid includes a matrix acidizing fluid, a wellbore cleanup fluid, a pickling fluid, a near wellbore damage cleanup fluid, a surfactant treatment fluid, an unviscosified fracture fluid (e.g. slick water fracture fluid), and/or any other fluid consistent with the fluids otherwise described herein. An oilfield treatment fluid may include any type of additive known in the art, which are not listed herein for purposes of clarity of the present description, but which may include at least friction reducers, inhibitors, surfactants and/or wetting agents, fluid diverting agents, particulates, acid retarders (except where otherwise provided herein), mineral acids, organic acids, chelating agents, energizing agents (e.g. C02 or N2), gas generating agents, solvents, emulsifying agents, flowback control agents, resins, breakers, and/or non- polysaccharide based viscosifying agents.

[0029] The term "high pressure pump" as utilized herein should be understood broadly. In certain embodiments, a high pressure pump includes a positive displacement pump that provides an oilfield relevant pumping rate - for example at least 0.5 barrels per minute (bpm), although the specific example is not limiting. A high pressure pump includes a pump capable of pumping fluids at an oilfield relevant pressure, including at least 500 psi, at least 1 ,000 psi, at least 2,000 psi, at least 5,000 psi, at least 10,000 psi, up to 15,000 psi, and/or at even greater pressures. Pumps suitable for oilfield cementing, matrix acidizing, and/or hydraulic fracturing treatments are available as high pressure pumps, although other pumps may be utilized.

[0030] Hydrofluoric acid exhibits reactions which are distinct from HCI, and therefore is useful in certain applications to enhance the treatment capability of an aqueous solution containing hydrofluoric acid. For example, hydrofluoric acid is utilized in the cleanup of sandstone formations where HCI alone is not effective for removing certain types of formation damage. In certain embodiments, the hydrofluoric acid is present in an amount of at least about 0.25% by weight. The hydrofluoric acid may be present in an amount of up to 2%, up to 6%, up to 10%, up to 15%, or greater amounts. [0031] Hydrofluoric acid or its precursors, in combination with other mineral or organic acids, may be used particularly effectively in matrix acidizing treatments. Matrix acidizing is a process in which an acidic fluid is injected into a formation at a pressure less than that necessary to fracture the rock. The acid then reacts with the subterranean formation in the vicinity of or near the wellbore. Although conventional treatments of siliceous clay containing formations with hydrofluoric acid containing acids (mud acids) have generally proven effective for a short time, the improvements in production are frequently short lived. One explanation for this phenomenon is that the mud acid reacts rapidly with the subterranean formation in the vicinity of or near wellbore area, often the first few inches around the wellbore, thus spending so rapidly that penetration deep into the subterranean formation is not achieved. Subsequently, fines in the subterranean formation migrate into the acidized area near wellbore area and replug the area. Additionally, at more extreme mineralogies, temperatures, and reservoir conditions, the dissolution reactions may be so rapid that the resulting precipitation reactions are often uncontrollable and can cause further formation damage.

[0032] Some embodiments in accordance with the disclosure relate to methods of matrix acidizing with a liquid, solid, or semi-solid hydrofluoric acid- precursor present in the treatment fluid. This may be achieved in several ways. The acid-precursor may be included in an otherwise conventional matrix acidizing treatment (in which the fluid contains a mineral acid such as HCI, an organic acid, or mixtures thereof). In general, as indicated, compositions used according to the disclosure, whether in a conventional matrix acidizing treatment, or other treatment type, may be prepared by mixing the required components in an aqueous liquid. The expression "aqueous liquid" is understood as including a wide spectrum of water- based liquids, including, but not limited to, fresh water, sea water, dilute acids, and brines, so long as any components of the aqueous liquid do not interfere significantly with the formation of or performance of the compositions of the disclosure. Additionally, as also indicated, one or more of the precursor compounds or compositions may first be blended with or dissolved in an aqueous liquid, if desired, before blending with aqueous liquid and one or more components to form the compositions used in accordance with the disclosure. As will be recognized by those skilled in the art, the aqueous liquid may contain additives, inhibitors, and the like, as is common in formation treatment procedures. Further, the sequence of blending the components of the mixtures is not critical, i.e. , the components or aqueous solutions thereof may be blended in any desired order or sequence. The aqueous liquid with which the hydrofluoric acid-precursor (also referred to as a fluorine generating source) may be a solution containing water, salt, alcohols, hydrocarbons, acids, polymers, and the like.

[0033] Acid-precursors, with or without accelerants, may be used particularly effectively in acid fracturing treatments in accordance with the disclosure. Acid fracturing is a process in which an acidic fluid is injected into a formation at a pressure sufficiently high to fracture the rock. One the fractures are formed, the acid then etches the surfaces of the fracture so that conductive flow paths are formed along the fracture faces. The flow paths formed remain after the pressure is released and the fracture faces are forced back together, or upon proppant placed there between. However, there are drawbacks with acid fracturing. First, acids, especially strong acids, react with the first material they encounter. In an acid fracturing treatment, as in matrix acidizing treatments, this means that as soon as a fracture forms or is enlarged, or as soon as a high permeability region is formed or encountered, both of which are likely to occur near the wellbore, acid will contact the fresh matrix surface near the wellbore, or in fluid contact with the high permeability region near the wellbore, and react with it. Most or all of the acid reaction then occurs near the wellbore, or in or near the high permeability region near the wellbore, and little or none of the acid reaches portions of the fracture farther from the wellbore, or farther away than the high permeability region. Therefore etched flow paths along the fracture faces are not formed very far away from the wellbore or beyond any high permeability regions. Second, for carbonate formations, once the acid begins to react with a portion of the matrix material, it tends to form "wormholes" or paths of least resistance that subsequent acid will follow. If either or both of these occurs, then when the pressure is released and the fracture closes, a satisfactory flow path for production of fluids, from the formation into the fracture and then into the wellbore, will not be formed.

[0034] Solid acid-precursors solve the above-described problems. Since the fluid is not sufficiently acidic when it is first injected, it will not react with the first formation material with which it comes into contact. Rather it will be carried farther into the growing fracture where the acid will subsequently react when it is released. Also, because the acid-precursor is a solid material in some aspects, if it is large it may assist in propping open the fracture until the differential etching occurs, but then after it is hydrolyzed the solid acid-precursor will no longer be present. In some aspects, if the solid acid-precursor becomes small, or even dissipates all together, it will not impede fluid flow from the formation into the wellbore for production.

[0035] In some acid fracturing embodiments, the solid acid-precursor may be included in an otherwise conventional acid fracturing treatment (in which the fluid contains an acid such as HCI, an organic acid or mixtures thereof). The initially present acids will tend to spend in the near-wellbore or high permeability region of the formation, but the solid acid-precursor will be carried farther into the fracture and generate acid in situ that will etch the fracture faces farther away from the wellbore. The solid acid-precursor may be the only source of acid in the treatment or it may be combined with another mineral or organic acid. Optionally, in some acid fracturing treatment embodiments, a proppant may be included to help keep the fracture open until the solid acid-precursor has hydrolyzed, dissolved, or otherwise dissipated.

[0036] In acid fracturing operations, often, significant amounts of acid- precursor are desirable. Rapid dissolution of the solid acid-precursor is may also be desirable, as long as too much dissolution does not occur too close to the wellbore in the formation fractures. If the particles dissolve too slowly then even dissolution of the formation rather than differential etching of fracture faces may result. Corrosion inhibitor may also be added to avoid solid acid-precursors particles from being entrapped and consumed, before they reach the target fracture area. In such circumstances, when trapped, their dissolution will generate an acid that will contact metal components. Also, in some aspects, an appropriate amount of buffer may be added to the treatment fluid, or to the particles, to counteract the effects of acid being generated by premature hydrolysis of the solid acid-precursor.

[0037] In some embodiments, the acid-precursor (with or without any additional solid acid-reactive material) may be used in a fracturing treatment, and when in solid form, it also acts as a proppant until it degrades, or otherwise a temporary proppant. The acid-precursor is pumped into the well and at a suitable temperature, degrades to the active acid, and reacts with the surface of the rock. When a large amount of particles of acid-precursor or mixture is used, it may be necessary to use a viscosified carrier fluid to avoid premature settling of the solid acid-precursor particles. Some other functions of acid generated from a hydrofluoric acid-precursors include use as a breaker or breaker aid for polymer or viscoelastic surfactant thickeners if they are present, as a dissolver of fluid loss additives, or as a dissolver of scales or fines, and the like.

[0038] Embodiments of the disclosure employ hydrofluoric acid-precursors such as fluorine generating sources. In embodiments the sources are liquid, solid, and semi-solid compositions including hydrogen fluoride compositions that facilitate the safe use, transport, and storage of hydrogen fluoride sources. Further, the chemical properties of the hydrogen fluoride in the compositions are substantially unchanged from those of hydrogen fluoride in its pure state and, thus, hydrogen fluoride may be readily and quantitatively recovered from the compositions.

[0039] In some embodiments, useful compositions include intimate mixtures of hydrogen fluoride and an effective amount of a polyacrylate/polyacrylamide cross- linked copolymers as fluorine generating sources. The sources are liquid, solid, and semi-solid (e.g., gelatinous) compositions that facilitate the safe use, transport, and storage of hydrogen fluoride. Further, the chemical properties of the hydrogen fluoride in the compositions are substantially unchanged from those of hydrogen fluoride in its pure state and, thus, hydrogen fluoride may be readily and quantitatively recovered from the compositions. Such compositions described herein can also include a carrier fluid. The carrier fluid can comprise a component selected from the group consisting of water, a viscosifier, an alcohol, a salt, an acid, a surfactant, and combinations thereof.

[0040] As used herein, the term "copolymer" means a polymer having two or more different monomer residues that have been polymerized and constructed as one or more chains. The arrangements of these monomer units in the chain include those that regularly alternate the different monomers or those that repeat monomer units in regular or random sequences. In addition, the chain can be straight, branched, or grafted, or can exist as a block copolymer. Also, as used herein, the term "cross-linked" means the attachment of two chains of polymer molecules by bridges composed of an element, a functional group, a compound, or a polymer unit, which join certain atoms of the chains by primary chemical bonds. The cross-linking can occur between two or more polymer chains to form a copolymer structure. The cross-linking can also occur between two or more copolymer chains that are similar in arrangement. In some cases, cross-linking occurs between amide groups and carboxylic groups of the copolymer.

[0041] When provided in a dry form, the cross-linked copolymer may be solid in the form of a powder, granules, pellets, fiber, fabrics, mats, pads, and the like. When exposed to hydrogen fluoride, the copolymer chains expand or unfold and uptake or absorb hydrogen fluoride to form a liquid, solid, or a semi-solid material, such a gel, depending on the molecular weight of the polymer. Due to the copolymer's cross-linking, the copolymer is insoluble in hydrogen fluoride and water. In some cases, the solid may have nanometer or micrometer scale dimensions.

[0042] Without wishing to be bound by any theory, it is believed that hydrogen fluoride uptake by the copolymer is facilitated by negatively charged carboxylic groups of the copolymer, and their ionic association with hydrogen fluoride molecules. For embodiments in which the copolymer comprises an alkali metal or ammonium ion (e.g. , copolymers formed with an acrylic acid salt), it is believed that, in the presence of hydrogen fluoride, the alkali metal or ammonium disassociates from the carboxyl group creating two ions: a carboxyl (COO-) and an alkali metal or ammonium ion (e.g. , NH₄ ⁺). The carboxyl groups begin to repel each other because they have the same negative charge. This repulsion unfolds or swells the polymer chain. The swelling action also allows more hydrogen fluoride to associate with the polymer chain and reside in the spaces within the polymer's network. The cations are also likely to associate with the hydrogen fluoride. Furthermore, hydrogen fluoride is also known to form complexes with amines, and the nitrogen groups in the polymer may also facilitate uptake of hydrogen fluoride by the polymer.

[0043] Further, the cross-linking between polymer chains may prevent the copolymer from dissolving in liquid hydrogen fluoride, or other liquids. When the chains become solvated, the crosslinks prevent them from moving around randomly. In general, the cross-linking affects the copolymer's adsorption capacity, with more crosslinks in a chain corresponding to a decrease in the polymer's ability to adsorb liquids. (See, e.g., Osmosis and Super Absorbent Polymers, U. of Illinois at Urbana- Champaign, incorporated herein in its entirety by reference thereto.). It is believed that cross-linked copolymers have a significantly higher capacity for liquid hydrogen fluoride compared to the copolymer's constituent polymers individually.

[0044] Suitable cross-linked copolymers may include copolymers constructed of both acrylamide units and acrylate units. Within the scope of the term "acrylamide", included is acrylamide itself (i.e. , 2-propenamide), polyacrylamides, polyalkylacrylamides (e.g., polymethylacrylamide), monomer residues of such acrylamides, and derivatives thereof. As used herein, the term "derivative" means a compound or chemical structure having the same fundamental structure or underlying chemical basis as the relevant related compound. Such a derivate is not limited to a compound or chemical structure produced or obtained from the relevant related compound. Acrylamide units that can be utilized in accordance with the disclosure include individual structural units of acrylamide, repeating units of acrylamide, and polymer chains constructed, at least in part, of acrylamides. Within the scope of the term "acrylate", included is acrylic acid (i.e., 2-propenoic acid), acrylic acid salt (e.g. , sodium acrylate, potassium acrylate, and the like), alkylacrylates (e.g. methyl acrylate, butyl methylacrylate, and the like), polyacrylates, polyalkylacrylates, polyacrylic salts, monomer residues of such acrylates, and derivatives thereof. Acrylate units that can be utilized include individual structural units of acrylates, repeating units of acrylates, and polymer chains constructed, at least in part, of acrylates. In some embodiments, acrylic acid salts include potassium acrylate, sodium acrylate, and ammonium acrylate.

[0045] Polyacrylate-polyacrylamide cross-linked copolymers are commercially available from a variety of sources including Degussa AG of Krefeld, Germany (sold under the trade name STOCKOSORB®), Kyoritsu Yukikogyo Kenkyusho of Japan (sold under the trade name Hymosab® 200), and Aldrich of Milwaukee, Wis. (Cat. No. 43,277-6). Copolymers may comprise from about 1 to about 99 weight percent, or from about 5 to about 60 weight percent, of acrylamide units based upon the total weight of the copolymer. Copolymers may also comprise from about 1 to about 99 weight percent, or from about 5 to about 60 weight percent, of acrylate units based upon the total weight of the copolymer. The cross-linked copolymers may molecular weights of from about 1 ,000 to about 10,000,000, or from about 5,000 to about 5,000,000.

[0046] The fluorine generating fluid may be prepared as follows: an effective amount of a cross-linked copolymer is mixed with hydrogen fluoride in any suitable corrosion resistant vessel to form an intimate mixture. An effective amount of cross- linked copolymer is an amount capable of decreasing the volatility and increasing the surface tension of the hydrogen fluoride to the level desired for the end use. Addition of the cross-linked copolymer and hydrogen fluoride may be performed in any sequence. Mixing may be accomplished by any means convenient, including without limitation, stirring or dispersing the copolymer into a pool of hydrogen fluoride or passing hydrogen fluoride gas over the cross-linked copolymer. The hydrogen fluoride may be commercially available anhydrous hydrogen fluoride having a water content of 0.1 % or less or aqueous hydrogen fluoride. The polymer may be in any form suitable for mixing with the hydrogen fluoride including, without limitation, granules, beads, pellets, fibers, or mats. Mixing will occur faster for smaller particle sizes of the polymer and slower for larger sizes. Mixing can be performed at temperatures from about 0 to about 100° C, or from about 10 to about 40° C, or from about 10 to about 25° C. Pressure is not critical to the mixing operation, although capacity may be lower at increased pressure.

[0047] The amount of hydrogen fluoride and cross-linked copolymer used will depend in part on the particular cross-linked copolymer selected and the desired end-use for the composition. If the cross-linked copolymer has a relatively low molecular weight, the resulting hydrogen fluoride/ cross-linked copolymer composition will be a viscous liquid. If the cross-linked copolymer has a relatively high molecular weight, the resulting composition will be a solid or semi-solid material (e.g., gel). Additionally, the amount of cross-linked copolymer used will determine whether or not the resulting composition is a solid or liquid. Generally, up to about 1 percent by weight, based on the total weight of the composition, of cross-linked copolymer is used the composition will be a viscous liquid. Compositions in which the amount of cross-linked copolymer is at least about 2 weight percent, generally, will take a gel-like semi-solid form.

[0048] It should be noted further that a higher weight percentage of cross- linked copolymer will lead to a greater the reduction in vapor pressure and an increase in surface tension. The reduction in surface tension will reduce hydrogen fluoride aerosolization. However, with an increase in weight percentage of cross- linked copolymer, the weight percentage of hydrogen fluoride in the composition decreases which may affect the composition's suitability for a desired end-use. Therefore, the effective amount of hydrogen fluoride and cross-linked copolymer used will depend on a consideration of a number of factors. From about 0.5 to about 99.9 weight percent of cross-linked copolymer and from about 99.5 to about 0.1 weight percent of hydrogen fluoride may be used. Also, from about 2 to about 50 weight percent cross-linked copolymer and from about 98 to about 50 weight percent hydrogen fluoride, or from about 2 to about 20 weight percent of cross-linked copolymer and from about 98 to about 80 weight percent of hydrogen fluoride may be used.

[0049] The cross-linked copolymers as disclosed have an exceptionally high capacity for hydrogen fluoride. It is possible to measure the capacity of a polymer for hydrogen fluoride by mixing the polymer with an excess of hydrogen fluoride, allowing the mixture to stand for a period of time such that the polymer becomes saturated, gravity or suction filtering off the excess hydrogen fluoride, and weighing the saturated polymer as well as the excess hydrogen fluoride.

[0050] Although cross-linked copolymer capacity is useful to a practical hydrogen fluoride -gel system, other properties should be considered as well. Other properties of interest include an exotherm upon mixing the copolymer and hydrogen fluoride, vapor pressure of the resulting composition, viscosity of the composition, gelatinization time, density per unit volume of the starting polymer, capacity of the composition under pressure, ease of recovery of the hydrogen fluoride from the composition, reduction in hydrogen fluoride aerosol formation by the system, and mixing or dispersing of the polymer into hydrogen fluoride. [0051] It is contemplated therefore, that in addition to polyacrylate/polyacrylamide cross-linked copolymers, other hydrogen fluoride - absorbing polymers and copolymers may be practiced. These other polymers and copolymers may be be mixed with the polyacrylate/polyacrylamide cross-linked copolymer to optimize several properties of the composition. For example, for applications in which the time required to gel a given quantity of hydrogen fluoride is of concern, the mixture can comprise a copolymer having high hydrogen fluoride capacity and another polymer or copolymer which gels quickly. The evolution of excessive heat may accompany the formation of the gel when hydrogen fluoride and a copolymer or polymer are mixed. Accordingly, embodiments utilize a mixture of a high capacity cross-linked copolymer and a polymer or copolymer with a lower capacity that exhibits a smaller exotherm.

[0052] Examples of other polymers that may be mixed with a polyacrylate/polyacrylamide cross-linked copolymer include those described in U.S. Pat. No. 6, 177,058, which is incorporated herein by reference in its entirety. Further polymers include water soluble polymers selected from the group consisting of cellulose ethers, modified starches, starch derivatives, natural gum derivatives, polyacrylic acid salts, ethylene oxide polymer, methacrylic acid polymer, polyethyleneimine polymer, polyvinyl pyrrolidone polymer and mixtures thereof. Additional polymers include polylactic acid, polymaleic acid, and polymethacrylic acid.

[0053] Hydrogen fluoride may be recovered readily from the composition by submitting the composition for example to downhole conditions such as higher temperatures found in the range of 0 to about 200° C, resulting in the liberation of fluorine.

[0054] The compositions as described provide a convenient and safe method for storing, transporting, handling, mixing and injecting downhole, the hydrogen fluoride source. Because the compositions exhibit little or no volatilization of hydrogen fluoride, the hazards of storing the hydrogen fluoride are significantly reduced. Additionally, the stored material may be safely transported. The compositions may be prepared and then placed in a storage container by any convenient means. The compositions may be prepared in the storage container. Suitable storage containers are those containers made of, or lined with, a hydrogen fluoride resistant material such as carbon steel, fluoropolymers, MONEL®, and the like. Storage of the compositions may be for any length of time provided that the compositions are not exposed to air or other chemicals. Storage may be under ambient conditions.

[0055] The stored composition may be safely and efficiently transported to a destination such as a wellsite. Transporting of the composition may employ any conventional means such as rail car or truck. Once delivered to the destination, the stored composition may be treated to recover the hydrogen fluoride from the composition for use. In embodiments, once at the wellsite, the compositions may be mixed with a carrier fluid and then pumped downhole to inject the oilfield treatment fluid into the formation at matrix rates and/or injecting the oilfield treatment fluid into the formation at a pressure that is at least equal to the hydraulic fracturing pressure. In addition to the use of the compositions described herein in acid related well treatments, such compositions may be equally applicable to any well operations where zonal isolation is required such as drilling operations, workover operations, etc.

[0056] The fluorine generating source (comprising the hydrogen fluoride and a polymer) may be pumped downhole through coiled tubing and mixed downhole with the carrier fluid. The fluorine generating source can be pumped through the annulus and mixed downhole with the carrier fluid which in this case could be pumped through coiled tubing.

[0057] The molecular weight of the polymer in the fluorine generating source may be alternated during pumping in order to achieve chemical diversion of the fluid downhole.

[0058] The fluorine generating source may also be used in a carrier fluid to remove siliceous scale including from tubulars, geothermal wells, and thermal EOR wells. The fluorine generating source may be used for matrix acidizing, acid fracturing, gravel pack damage removal, so called frac-pack, drilling mud removal, or hydraulic fracturing operations. [0059] Also, as described above, the fluorine generating source may be treated for example by increased temperature in order to recover hydrogen fluoride; the treatment may occur before, during, or after mixing with the carrier fluid on surface or the temperature may be increased downhole via, for example, contacting the formation.

[0060] The compositions described herein (and methods of use thereof) can contain a viscosifier in an amount to impart suitable viscosity properties into the fluid, as described above. Any suitable viscosifier readily known to those of skill in the art for its ability to generate adequate viscosity properties for the treatment operation may be used. Such viscosifiers include, but are not necessarily limited to, surfactants, such as viscoelastic surfactants, a polysaccharide or chemically modified polysaccharide, polymers such as cellulose, derivatized cellulose, guar gum, derivatized guar gum, xanthan gum, or synthetic polymers such as polyacrylamides and polyacrylamide copolymers. Useful are ionically modified polysaccharides which are regularly substituted, such as those described in U.S. patent application Ser. No. 1 1/366,677, incorporated herein by reference thereto. The viscosifier may be incorporated in an amount suitable to provide measured fluid viscosity from about 20 mPa-s to about 400 mPa-s at a shear rate of 100 s^_1 over a temperature range from about 80° F. to about 300° F., or from about 40 mPa-s to about 400 mPa-s at a shear rate of 100 s^_1 over a temperature range from about 80° F. to about 300° F. Fluids may further contain various additives well known in stimulation treatments (such as, for example, corrosion inhibitors, iron control agents, surfactants, clay control additives, buffers, scale inhibitors and the like) provided that the additives do not interfere with the desired action or stability of the fluid.

[0061] A fiber component may be included in fluids useful in accordance with the disclosure to achieve a variety of properties including improving particle suspension, and particle transport capabilities, and gas phase stability. Fibers used may be hydrophilic or hydrophobic in nature. Fibers can be any fibrous material, such as, but not necessarily limited to, natural organic fibers, comminuted plant materials, synthetic polymer fibers (by non-limiting example polyester, polyaramide, polyamide, novoloid or a novoloid-type polymer), fibrillated synthetic organic fibers, ceramic fibers, inorganic fibers, metal fibers, metal filaments, carbon fibers, glass fibers, ceramic fibers, natural polymer fibers, and any mixtures thereof. Particularly useful fibers are polyester fibers coated to be highly hydrophilic, such as, but not limited to, DACRON® polyethylene terephthalate (PET) Fibers available from Invista Corp. Wichita, Kans., USA, 67220. Other examples of useful fibers include, but are not limited to, polylactic acid polyester fibers, polyglycolic acid polyester fibers, polyvinyl alcohol fibers, and the like. When used, the fiber component may be included at concentrations from about 1 to about 15 grams per liter of the liquid phase of the fluid, from about 2 to about 12 grams per liter of liquid, or even from about 2 to about 10 grams per liter of liquid.

[0062] As discussed above, the methods described herein can also include placing proppant particles. The proppant particles may be substantially insoluble in the fluids of the formation. Proppant particles carried by the treatment fluid remain in the fracture created, thus propping open the fracture when the fracturing pressure is released and the well is put into production. Suitable proppant materials include, but are not limited to, sand, walnut shells, sintered bauxite, glass beads, ceramic materials, naturally occurring materials, or similar materials. Mixtures of proppants can be used as well. If sand is used, it can be from about 20 to about 100 U.S. Standard Mesh in size. Naturally occurring materials may be underived and/or unprocessed naturally occurring materials, as well as materials based on naturally occurring materials that have been processed and/or derived. Suitable examples of naturally occurring particulate materials for use as proppants include, but are not necessarily limited to: ground or crushed shells of nuts such as walnut, coconut, pecan, almond, ivory nut, brazil nut, etc.; ground or crushed seed shells (including fruit pits) of seeds of fruits such as plum, olive, peach, cherry, apricot, etc.; ground or crushed seed shells of other plants such as maize (e.g. , corn cobs or corn kernels), etc.; 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 particalization, processing, etc. Further information on nuts and composition thereof may be found in Encyclopedia of Chemical Technology, Edited by Raymond E. Kirk and Donald F. Othmer, Third Edition, John Wiley & Sons, Volume 16, pages 248-273 (entitled "Nuts"), Copyright 1981 , which is incorporated herein by reference.

[0063] The concentration of proppant in the fluid can be any concentration known in the art, and will in some cases, be in the range of from about 0.05 to about 3 kilograms of proppant added per liter of liquid phase. Also, any of the proppant particles can further be coated with a resin to potentially improve the strength, clustering ability, and flow back properties of the proppant.

[0064] EXAMPLES

[0065] Example 1

[0066] Solution A

[0067] A 40 g quantity of water was absorbed over several hours by a 1 g quantity of a polyacrylate/polyacrylamide cross-linked copolymer (hereinafter referred to as "copolymer") obtained from Evonik Industries to form Solution A.

[0068] Solution B

[0069] A 10 g quantity of 40 wt% aqueous hydrogen fluoride was added to 490 g of water for a final concentration of 0.8 wt% hydrogen fluoride to form Solution B.

[0070] Solution C

[0071] A 10 g quantity of 40 wt% aqueous hydrogen fluoride was absorbed over several hours by 2 g of the copolymer .The mixture was then added to 490 g of water for a final concentration of 0.8 wt% hydrogen fluoride to form Solution C. [0072] Solution D

[0073] A 12.5 g quantity of 40 wt% aqueous hydrogen fluoride and 10 g of 99.7 wt% acetic acid ("AA") were absorbed together over several hours by 2 g of the copolymer .The mixture was then added to 35.1 g of 99.7 wt% acetic acid and 440.4 g of water for a final concentration of 1 wt% hydrogen fluoride and 9 wt% acetic acid.

[0074] Finally, 50 g quantities of silica flour were added to each of the Solutions A-D, and each of the solutions were raised to 250 °F. Samples of the solutions were taken at various intervals over a 2 hour period and tested for silicon content, results shown in Figure 1. As can be seen in Figure 1 , solutions C and D (including hydrogen fluoride absorbed into the copolymer) showed similar silicon dissolution activity to that of solution B (aqueous hydrogen fluoride).

[0075] Example 2

[0076] Solution E

[0077] A 12.5 g quantity of 40 wt% aqueous hydrogen fluoride and 45.1 g of 99.7 wt% acetic acid were added to 442.4 g water for a final concentration of 1 wt% hydrogen fluoride and 9 wt% acetic acid.

[0078] Finally, 50 g quantities of kaolinite were added to each of the Solutions D (described in Example 1 ) and Solution E, and each of the solutions were raised to 250 °F. Samples of the solutions were taken at various intervals and tested for silicon and aluminum content, results shown in Figures 2 and 3. Figures 2 and 3 show that the copolymer initially binds the hydrogen fluoride and releases hydrogen fluoride as the solution heats up and the reaction progresses. After about 120 minutes of reaction the Si and Al concentrations in Solutions D and E are similar indicating that hydrogen fluoride has been almost fully released.

[0079] Example 3 [0080] Finally, 50 g quantities of kaolinite were added to each of the Solutions D (described in Example 1 ) and Solution E (described in Example 2), and each of the solutions were held at 70 °F. Samples of the solutions were taken at various intervals and tested for silicon and aluminum content, results shown in Figures 4 and 5. As shown in Figures 4 and 5, solution D showed significantly reduced silicon and aluminum dissolution activity over time as compared to that of Solution E, demonstrating the ability of the copolymer to bind hydrogen fluoride at this temperature. Calculations based on the Al and Si concentrations in Figures 4 and 5 show that Solution D has approximately 25% less hydrogen fluoride available for reaction with kaolinite compared to Solution E. The available hydrogen fluoride for reaction in Solution D can be adjusted by changing the hydrogen fluoride to copolymer ratio. If less copolymer is added, more hydrogen fluoride is expected to be available for reaction.

[0081] The foregoing description of the embodiments has been provided for purposes of illustration and description. Examples of the compositions and methods are provided so that this disclosure will be sufficiently thorough, and will convey the scope to those who are skilled in the art. Numerous specific details are set forth such as examples of specific components, devices, and methods, to provide a thorough understanding of aspects of the disclosure, but are not intended to be exhaustive or to limit the disclosure. It will be appreciated that it is within the scope of the disclosure that individual elements or features of a particular embodiment are generally not limited to that particular embodiment, but, where applicable, are interchangeable and can be used in a selected embodiment, even if not specifically shown or described. The same may also be varied in many ways. Such variations are not to be regarded as a departure from the disclosure, and all such modifications are intended to be included within the scope of the disclosure.

[0082] Also, in some example embodiments, well-known processes, well- known device structures, and well-known technologies are not described in detail. Further, it will be readily apparent to those of skill in the art that in the design, preparation and operation of compositions and methods to achieve that described in the disclosure, variations in design, formulation, and condition may present, for example. [0083] Although a few embodiments of the disclosure have been described in detail above, those of ordinary skill in the art will readily appreciate that many modifications are possible without materially departing from the teachings of this disclosure. Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims.

Claims

CLAI MS What is claimed is:

1 . A composition comprising:

(i) a fluorine generating source comprising hydrogen fluoride and a copolymer, wherein the copolymer comprises ionizable functional groups of the copolymer associated with the hydrogen fluoride; and

(ii) a carrier fluid.

2. The composition of claim 1 , wherein the fluorine generating source is in a liquid, solid, or semi-solid form; and the carrier fluid comprises a component selected from the group consisting of water, a viscosifier, an alcohol, a salt, an acid, a surfactant, and combinations thereof.

3. The composition of claim 1 , wherein the copolymer is a polyacrylate/polyacrylamide cross-linked copolymer.

4. The composition of claim 1 , wherein the copolymer comprises from about 1 to about 99 weight percent, of acrylamide units and from about 1 to about 99 weight percent of acrylate units based upon the total weight of the copolymer.

5. The composition of claim 1 wherein the copolymer is a cross-linked copolymer comprised of water soluble polymers selected from the group consisting of cellulose ethers, modified starches, starch derivatives, natural gum derivatives, polyacrylic acid salts, ethylene oxide polymer, methacrylic acid polymer, polyethyleneimine polymer, polyvinyl pyrrolidone polymer, polylactic acid, polymaleic acid, polymethacrylic acid and mixtures thereof.

6. The composition of claim 5, wherein the copolymers have a molecular weight of from about 1 ,000 to about 10,000,000.

7. A method for treating a subterranean formation penetrated by a wellbore, the method comprising: (i) forming a mixture of a fluorine generating source and a carrier fluid, wherein the fluorine generating source comprises hydrogen fluoride and a copolymer, wherein the copolymer comprises ionizable functional groups of the copolymer associated with the hydrogen fluoride; and

(ii) contacting the subterranean formation with the mixture.

8. The method of claim 7, wherein the forming the mixture is performed at the surface in mixing equipment adjacent the wellbore.

9. The method of claim 7, wherein the forming the mixture is performed in the wellbore.

10. The method of claim 9, wherein the forming the mixture in the wellbore is performed by pumping the fluorine source or the carrier fluid through a coiled tubing.

1 1 . The method of claim 7, wherein treating is one of matrix acidizing, acid fracturing, gravel pack damage removal, frac-pack, drilling mud removal, and hydraulic fracturing.

12. The method of claim 7 further comprising creating a fracture in the subterranean formation, and placing the fluorine generating source in the fracture, wherein the hydrogen fluoride is released after placing the fluorine generating source in the fracture.

13. The method of claim 12, wherein the mixture further comprises a proppant, and wherein the proppant is placed in the fracture concurrent with the fluorine generating source.

14. The method of claim 12, wherein the fluorine generating source is capable of propping open the fracture until the hydrogen fluoride is released from the copolymer.

15. The method of claim 12, wherein the fluorine generating source is in a liquid, solid, or semi-solid form; and the carrier fluid comprises a component selected from the group consisting of water, a viscosifier, an alcohol, a salt, an acid, a surfactant, and combinations thereof.

16. The method of claim 7, wherein the copolymer is polyacrylate/polyacrylamide cross-linked copolymer.

17. The composition of claim 7, wherein the copolymer comprises from about 1 to about 99 weight percent of acrylamide units, and from about 1 to about 99 weight percent of acrylate units based upon the total weight of the copolymer.

18. The composition of claim 7 wherein the copolymer is a cross-linked copolymer comprised of water soluble polymers selected from the group consisting of cellulose ethers, modified starches, starch derivatives, natural gum derivatives, polyacrylic acid salts, ethylene oxide polymer, methacrylic acid polymer, polyethyleneimine polymer, polyvinyl pyrrolidone polymer, polylactic acid, polymaleic acid, polymethacrylic acid and mixtures thereof.

19. The composition of claim 18, wherein the copolymers have a molecular weight of from about 1 ,000 to about 10,000,000.

20. A method comprising:

(i) forming a mixture of a fluorine generating source and a carrier fluid, wherein the fluorine generating source comprises hydrogen fluoride and a copolymer, wherein the copolymer comprises ionizable functional groups of the copolymer associated with the hydrogen fluoride; and wherein the carrier fluid comprises a component selected from the group consisting of water, a viscosifier, an alcohol, a salt, an acid, a surfactant, and combinations thereof;

(ii) injecting the mixture into a wellbore penetrating a subterranean formation at a pressure equal to or below the fracture initiation pressure of the subterranean formation; and

(iii) allowing the fluorine generating source to release hydrogen fluoride in order to dissolve siliceous scale in tubulars, treat a geothermal well, treat a thermal oil recovery well, or matrix acidize a siliceous formation.