WO2014164835A1

WO2014164835A1 - Chelant acid particulate bridging solids for acid based wellbore fluids

Info

Publication number: WO2014164835A1
Application number: PCT/US2014/023591
Authority: WO
Inventors: David Ballard; Anne BECKLY
Original assignee: M-I Drilling Fluids U.K. Limited; M-I L.L.C.
Priority date: 2013-03-13
Filing date: 2014-03-11
Publication date: 2014-10-09

Abstract

A wellbore fluid may include a solid phosphonic acid-type chelant and base fluid. A method of performing wellbore operations may include injecting a wellbore fluid into a wellbore, the wellbore fluid including a solid phosphonic acid-type chelant; and a base fluid. Such wellbore operations may include drilling, completion, fracturing, stimulation, and diverting operations.

Description

CHELANT ACID PARTICULATE BRIDGING SOLIDS FOR ACID BASED WELLBORE FLUIDS

BACKGROUND

[0001] Hydrocarbons (oil, natural gas, etc.) are typically obtained from a subterranean geologic formation (i.e., a "reservoir") by drilling a well that penetrates the hydrocarbon- bearing formation. In order for hydrocarbons to be "produced," that is, travel from the formation to the wellbore (and ultimately to the surface), there must be a sufficiently unimpeded flowpath from the formation into the wellbore. One parameter that influences the rate of production is the permeability of the formation along the flowpath that the hydrocarbon must travel to reach the wellbore. Sometimes, the formation rock has a naturally low permeability; other times, the permeability is reduced during, for instance, drilling the well.

[0002] During the drilling of a wellbore, a variety of so-called wellbore fluids are typically used in the well for a variety of functions. When a well is drilled, a drilling fluid is often circulated into the hole to contact the region of a drill bit, for a number of reasons such as: to cool the drill bit, to carry the rock cuttings away from the point of drilling, and to maintain a hydrostatic pressure on the formation wall to prevent production during drilling. The drilling fluids may be circulated through a drill pipe and drill bit into the wellbore, and then may subsequently flow upward through wellbore to the surface. During this circulation, the drilling fluid may act to remove drill cuttings from the bottom of the hole to the surface, to suspend cuttings and weighting material when circulation is interrupted, to control subsurface pressures, to maintain the integrity of the wellbore until the well section is cased and cemented, to isolate the fluids from the formation by providing sufficient hydrostatic pressure to prevent the ingress of formation fluids into the wellbore, to cool and lubricate the drill string and bit, and/or to maximize penetration rate.

[0003] During well operations, the drilling fluid can be lost by leaking into the formation.

To prevent this, the drilling fluid is often intentionally modified so that a small amount leaks off and forms a coating on the wellbore surface (often referred to as a "filtercake") and thereby protecting the formation. Filtercakes are formed when particles suspended in a wellbore fluid coat and plug the pores in the subterranean formation such that the filtercake prevents or reduces both the loss of fluids into the formation and the influx of fluids present in the formation. A number of ways of forming filtercakes are known in the art, including the use of bridging particles, cuttings created by the drilling process, polymeric additives, and precipitates. Fluid loss pills may also be used where a viscous pill comprising a polymer may be used to reduce the rate of loss of a wellbore fluid to the formation through its viscosity.

[0004] Upon completion of drilling, the filtercake and/or fluid loss pill may stabilize the wellbore during subsequent completion operations such as placement of a gravel pack in the wellbore. Additionally, during completion operations, when fluid loss is suspected, a fluid loss pill of polymers may be "spotted" or placed in the wellbore. Other completion fluids may be injected behind the fluid loss pill into a position within the wellbore which is immediately above a portion of the formation where fluid loss is suspected. Injection of fluids into the wellbore is then stopped, and fluid loss will then move the pill toward the fluid loss location to coat the formation and prevent or reduce future fluid loss.

[0005] After any completion operations have been accomplished, the filtercake (formed during drilling and/or completion) on the sidewalls of the wellbore must typically be removed, because remaining residue of the filtercake may negatively impact production. That is, although filtercake formation and use of fluid loss pills are essential to drilling and completion operations, the barriers may be a significant impediment to the production of hydrocarbons or other fluids from the well, if, for example, the rock formation is still plugged by the barrier. Because the filtercake is compacted onto the rock face, it often adheres strongly to the formation and may not be readily or completely flushed out of the formation by another fluid degrading the filtercake on the wall.

[0006] Various types of solids may be suspended in wellbore fluids to bridge or block the pores of a subterranean formation (or holes of a screen) in a filter cake. Representative bridging solids include, but are not limited to, magnesium and calcium carbonate, limestone, marble, dolomite, iron carbonate, iron oxide, and magnesium oxide.

DETAILED DESCRIPTION

[0007] One or more aspects of the present disclosure may be directed to wellbore fluids incorporating chelants present in a solid or particulate form therein, as well as to methods of using such wellbore fluids. Specifically, by using chelants in solid or particulate form (and thus wellbore conditions supporting the solid form), a wellbore fluid may include such solids as bridging solids, that may be easily removable from formation pore throats and filter cakes upon the desired length of time. In one or more embodiments, by raising the pH of the fluid, the solid chelants may solubilize and simultaneously serve as a chelating agent to aid in further well clean-up, scale prevention, or corrosion inhibition. Thus, the solid particles may serve a dual role, their role being triggered by a change in the pH of the well.

[0008] In one or more embodiments, the solid chelants that may be used in the wellbore fluids of the present disclosure may include phosphonic acid-type chelants. Phosphonic acid type chelants are defined as chelants comprising a phosphonic acid moiety (- PO₃H₂) or its derivative -PO₃R₂ wherein R may be an alkyl or aryl radical. Suitable phosphonic acid-type chelants may include, but are not limited to, aminopolyphosphonic acids, polyphosphonic acids, derivatives thereof, and mixtures thereof. Suitable polyphosphonic acids and polyphosphonic derivatives include compounds having the formula (I) below:

wherein: X may be -OH or -NH₂; R may be an aryl radical, an aliphatic radical having 1 to 5 carbon atoms, or the radical (la) below:

and wherein each R₂ are independently selected from H or alkyl radicals having from 1 to 5 carbon atoms.

[0009] Suitable aminopolyphosphosphonic acid and aminopolyphosphosphonic derivatives may include chelants having the following formula (II):

wherein each Ri are independently selected from H or C1-C3 alkyl.

[0010] In one or more embodiments, phosphonic acid type chelants for use herein may have the formula (III) below:

wherein each X are independently selected from hydrogen or alkyl radicals, including hydrogen or alkyl radicals having from 1 to 4 carbon atoms; and each R is independently selected from -P0₃H₂ or a group having the formula (Ilia) below:

where n may range from 1 to 6. Examples of chelants according to Formula (III) for use herein are aminotri-(l-ethylphosphonic acid), ethylenediaminetetra-(l-ethylphosphonic acid), aminotri-(l-propylphosphonic acid), aminotri-(isopropylphosphonic acid) and chelants having the formula (IV) below:

wherein each R₂ are independently selected from -PO₃H₂ or a group having the formula (IVa) below:

where n may range from 1 to 6. Specific examples of chelants according to formula (IV) for use herein may include, but are not limited to, aminotris (methylenephosphonic acid) (ATMP), ethylene-diamine-tetra-(methylenephosphonic acid) (EDTMP) and diethylene- triamine-penta- (methylenephosphonic acid) (DTPMP). In one or more embodiments, the solid phosphonic acid-type chelant may include one or more of the following: 2-aminoethylphosphonic acid (AEPn), 1 -hydroxy ethylidene-l,l-diphosphonic acid (HEDP), amino tris(methylene phosphonic acid) (ATMP), ethylenediamine tetra(methylene phosphonic acid) (EDTMP); tetramethylenediamine tetra(methylene phosphonic acid) (TDTMP), hexamethylenediamine tetra(methylene phosphonic acid) (HDTMP), diethylenetriamine penta(methylene phosphonic acid) (DTPMP), and amino-tris-(methylene -phosphonic acid) (AMP).

[0012] Further, in one or more embodiments, the above formulas may be modified to include carboxylic acid groups in the place of one or more of any of the phosphonic acid groups, so long as one phosphonic acid group is still present in the molecule. Examples of such phosphonic acid and carboxylic acid group containing compounds include, without limitation, phosphonobutane-tricarboxylic acid (PBTC), N- (phosphonomethyl)iminodiacetic acid (PMIDA), 2-carboxyethyl phosphonic acid (CEPA), and 2-hydroxyphosphonocarboxylic acid (HPAA).

[0013] In one or more embodiments of the present disclosure, the above explained solid chelants may be used in any wellbore fluid such as drilling, cementing, completion, packing, work-over (repairing), stimulation, well killing, spacer fluids, etc. Such alternative uses, as well as other uses, of the present fluid should be apparent to one of skill in the art given the present disclosure. Depending on the particular application, the amount of solid chelant incorporated into the fluid may vary. However, in one or more embodiments, the solid chelant may be incorporated in an amount that is at least 5 pounds per barrel, at least 10 pounds per barrel, or at least 20 pounds per barrel. Further, the wellbore fluid may be a water-based fluid, or an oil-based fluid, including wholly oil- based fluids as well as invert or direct emulsions.

[0014] Water-based wellbore fluids may have an aqueous fluid as the base liquid and in which the solid chelants of the present disclosure may be used. The aqueous fluid may include at least one of fresh water, sea water, brine, mixtures of water and water-soluble organic compounds and mixtures thereof. For example, the aqueous fluid may be formulated with mixtures of desired salts in fresh water. Such salts may include, but are not limited to, alkali metal halides, hydroxides, or carboxylates, for example. In various embodiments of the drilling fluid disclosed herein, the brine may include seawater, aqueous solutions wherein the salt concentration is less than that of sea water, or aqueous solutions wherein the salt concentration is greater than that of sea water. Salts that may be found in seawater include, but are not limited to, sodium, calcium, aluminum, magnesium, potassium, strontium, lithium, and salts of chlorides, bromides, carbonates, iodides, chlorates, bromates, formates, nitrates, oxides, sulfates, silicates, phosphates, and fluorides. Salts that may be incorporated in brine include any one or more of those present in natural seawater or any other organic or inorganic dissolved salts. Additionally, brines that may be used in the drilling fluids disclosed herein may be natural or synthetic, with synthetic brines tending to be much simpler in constitution. In one embodiment, the density of the drilling fluid may be controlled by increasing the salt concentration in the brine (up to saturation). In a particular embodiment, a brine may include halide or carboxylate salts of mono- or divalent cations of metals, such as cesium, potassium, calcium, zinc, and/or sodium. Further, in one or more embodiments, the aqueous fluid may be adjusted to have a pH of less than 7, less 5, less than 4, or less than 2, depending on the particular chelant being used (i.e., the pH may initially be less than the first pKa value of the particular chelant to ensure presence of the chelant in acid (and solid) form. Such acidic pH may be achieved by incorporating one or more acids, including inorganic and organic acids (as well as compounds releasing organic acids upon hydrolysis), including hydrochloric acid, formic acid, and acetic acid. In one or more embodiments, depending on the manner in which the fluid is being used, the acid may be incorporated in an amount ranging from about 1 to about 20 percent by volume of the fluid.

[0015] The invert emulsion wellbore fluids may include an oleaginous continuous phase, a non-oleaginous discontinuous phase, and the solid chelants. Direction emulsions may include a non-oleaginous continuous phase, an oleaginous discontinuous phase, and solid chelants. However, oil based fluids may also be formed from 100% oleaginous fluids in which the solid chelants (as well as any other additives) may be dispersed.

[0016] The oleaginous fluid (forming any type of oil-based fluids) may be a liquid, a natural or synthetic oil, the oleaginous fluid may be selected from the group including diesel oil, mineral oil, a synthetic oil, such as hydrogenated and unhydrogenated olefins including polyalphaolefms, linear and branched olefins and the like, polydiorganosiloxanes, siloxanes, or organosiloxanes, esters of fatty acids, specifically straight chain, branched and cyclical alkyl ethers of fatty acids, similar compounds known to one of skill in the art, and mixtures thereof. For invert emulsions, the concentration of the oleaginous fluid should be sufficient so that an invert emulsion forms and may be less than about 99% by volume of the invert emulsion. In one embodiment, the amount of oleaginous fluid is from about 30% to about 95% by volume and more specifically about 40% to about 90% by volume of the invert emulsion fluid. The oleaginous fluid, in one embodiment, may include at least 5% by volume of a material selected from the group including esters, ethers, acetals, dialkylcarbonates, hydrocarbons, and combinations thereof.

[0017] The non-oleaginous fluid used in the formulation of the invert or direct emulsion fluid disclosed herein is a liquid and may be an aqueous liquid. In one embodiment, the non-oleaginous liquid may be selected from the group including sea water, a brine containing organic and/or inorganic dissolved salts, liquids containing water-miscible organic compounds, and combinations thereof. When forming an invert emulsion, the amount of the non-oleaginous fluid is typically less than the theoretical limit needed for forming an invert emulsion. Thus, in one embodiment, the amount of non-oleaginous fluid is less that about 70% by volume, and specifically from about 1 % to about 70%> by volume. In another embodiment, the non-oleaginous fluid is preferably from about 5% to about 60%) by volume of the invert emulsion fluid.

[0018] The solid chelants of the present disclosure may be included in a wellbore fluid that, depending on the stage at which the wellbore fluid is injected into the wellbore, may have one or other components in addition to a base fluid. Thus, in one or more embodiments, the solid chelants of the present disclosure may be used alone or in combination with conventional solid bridging agents (e.g., calcium carbonates, etc.).

[0019] Particular additives that may be included in the wellbore fluid compositions include viscosifiers and/or suspending agents, including various natural or synthetic polymers, viscoelastic surfactants, and silica powder. In one or more embodiments, the visocosifier may be incorporated in the fluid in an amount ranging from 0.01 to about 15 weight percent, based upon the total weight of the composition, or from about 0.10 to about 3 weight percent in one or more other embodiments. Examples of such natural polymers may include starch, schleroglucans, guar gums, xanthan gum, diutan, hydroxyethyl cellulose, carboxymethyl cellulose, welan gum, agar, carrageenan, gum Arabic, tragacanth gum, alginic acid, gellan gum, ghatti gum, locust bean gum, sodium alginate, mastic gum, beta-glucan, tara gum, chicle gum, glucomannan, dammar gum, karaya gum. Examples of synthetic polymers include, for example, polymers formed from monomers selected from acrylamide (AM), 2-acryamido-2-methylpropane sulfate acid (AMPS) and acrylic acid(AA), methacrylatoethyl trimethyl ammonium chloride (DMC) and propylene diene dimethyl ammonium chloride (DMDAAC), N, N-dimethyl acrylamide (DMAM) and N-vinyl pyrrolidone (NVP), as well as copolymers thereof, in addition to other viscosifiers used in fracturing fluids, drilling fluids, etc.

[0020] Other additives that may be included in the wellbore fluids disclosed herein include, for example, wetting agents, organophilic clays, viscosifiers, fluid loss control agents, surfactants, solvents, dispersants, interfacial tension reducers, pH adjusting chemicals, mutual solvents, thinners, thinning agents, cleaning agents, breaking agents (oxidizers, acid sources, enzymes), corrosion inhibitors, gelling agents, emulsifiers, diverting agent, etc. The addition of such agents should be well known to one of ordinary skill in the art of formulating wellbore fluids and muds.

[0021] During a drilling process, the fluid may be injected through the center of the drill string to the drill bit and exits in the annulus between the drill string and the wellbore, fulfilling, in this manner, the cooling and lubrication of the bit, casing of the well, and transporting the drill cuttings to the surface. During this process, some quantity of fluid may be filtrated into the subterranean formation through the side walls of the wellbore, so as to produce a filter cake of polymeric components and the particulate components (the solid chelants in one or more embodiments) bridging numerous pores in the sidewalls of the wellbore. [0022] When being used as a fluid loss pill, a viscous pill may be spotted or bullheaded into the appropriate location to reduce the rate of loss of a wellbore fluid to the formation through its viscosity or the viscous, bridging-solids-laden pill may be spotted or bullheaded into the appropriate location to reduce the rate of loss of a wellbore fluid to the formation by building a filtercake. Alternatively or in addition, various types of solids may optionally be suspended in wellbore fluids to bridge or block the holes of or gaps in a screen, thereby building a filtercake on the screen.

[0023] After completion of the drilling or completion process, the filter cake may be broken by application of a breaker fluid (that, in one or more embodiments, may contain the solid chelants). The breaker fluid may be circulated in the wellbore during or after the performance of the at least one completion operation. In other embodiments, the breaker fluid may be circulated either after a completion operation or after production of formation fluids has commenced to destroy the integrity of and clean up residual drilling fluids remaining inside casing or liners. The breaker fluid contributes to the degradation and removal of the filtercake deposited on the sidewalls of the wellbore or on the gaps in a screen to minimize negatively impacting production.

[0024] Generally, a well is often "completed" to allow for the flow of hydrocarbons out of the formation and up to the surface. As used herein, completion processes may include one or more of the strengthening the well hole with casing, evaluating the pressure and temperature of the formation, and installing the proper completion equipment to ensure an efficient flow of hydrocarbons out of the well or in the case of an injector well, to allow for the injection of gas or water. Completion operations, as used herein, may specifically include open hole completions, conventional perforated completions, sand exclusion completions, permanent completions, multiple zone completions, and drainhole completions, as known in the art. A completed wellbore may contain at least one of a slotted liner, a predrilled liner, a wire wrapped screen, an expandable screen, a sand screen filter, an open hole gravel pack, or casing.

[0025] Breaker fluids as disclosed herein may also be used in a cased hole to remove any drilling fluid left in the hole during any drilling and/or displacement processes. Well casing may consist of a series of metal tubes installed in the freshly drilled hole. Casing serves to strengthen the sides of the well hole, ensure that no oil or natural gas seeps out of the well hole as it is brought to the surface, and to keep other fluids or gases from seeping into the formation through the well. Thus, during displacement operations, typically, when switching from drilling with an oil-based mud to a water-based mud (or vice-versa), the fluid in the wellbore is displaced with a different fluid. For example, an oil-based mud may be displaced by another oil-based displacement to clean the wellbore. The oil-based displacement fluid may be followed with a water-based displacement fluid prior to beginning drilling or production. Conversely, when drilling with a water-based mud, prior to production, the water-based mud may be displacement water-based displacement, followed with an oil-based displacement fluid. Further, one skilled in the art would appreciate that additional displacement fluids or pills, such as viscous pills, may be used in such displacement or cleaning operations as well, as known in the art.

[0026] Another embodiment of the present disclosure involves a method of cleaning up a well bore drilled with a water based or oil based drilling fluid. In one such illustrative embodiment, the method involves circulating a breaker fluid disclosed herein in a wellbore, and then shutting in the well for a predetermined amount of time to allow penetration and fragmentation of the filter cake to take place. Upon fragmentation of the filter cake, the residual drilling fluid may be easily washed out of the wellbore. Alternatively, a wash fluid (different from the breaker fluid) may be circulated through the wellbore prior to commencing production.

[0027] Another embodiment of the present disclosure involves a method of cleaning up a wellbore drilled with a water based or oil based drilling fluid. In one such illustrative embodiment, the method involves circulating a breaker fluid disclosed herein in a wellbore, and then shutting in the well for a predetermined amount of time to allow penetration and fragmentation of the filter cake to take place. Upon fragmentation of the filter cake, the residual drilling fluid may be easily washed out of the well bore. Alternatively, a wash fluid (different from the breaker fluid) may be circulated through the wellbore prior to commencing production. [0028] However, the breaker fluids disclosed herein may also be used in various embodiments as a displacement fluid and/or a wash fluid. As used herein, a displacement fluid is typically used to physically push another fluid out of the wellbore, and a wash fluid typically contains a surfactant and may be used to physically and chemically remove drilling fluid residing in downhole tubulars. When also used as a displacement fluid, the breaker fluids of the present disclosure may act effectively push or displace the drilling fluid. When also used as a wash fluid, the breaker fluids may assist in physically and/or chemically removing the filter cake once the filter cake has been disaggregated by the breaker system.

[0029] In another embodiment, a breaker fluid disclosed herein may be used in the production of hydrocarbons from a formation. Following the drilling of a formation with an drilling mud, at least one completion operation may be performed on the well. A breaker fluid may then be circulated in the well, and the well may be shut for a predetermined time to allow for breaking of the filter cake formed on the walls therein. Formation fluids may then enter the well and production of the formation fluids may ensue. Alternatively, a wash fluid (different from the breaker fluid) may be circulated through the wellbore prior to commencing production of formation fluid.

[0030] In one or more embodiments, the solid chelants may be solubilized during the exposure to breaker fluid after a period of time, such as at least 6 hours, at least 10 hours, at least 15 hours, or at least 20 hours. However, the exact period of time may vary depending on the initial pH, temperature, changes in pH, etc. Such time frame may allow for the placement of the breaker, removing any previously used equipment from the wellbore, and placing other equipment, such as production equipment, downhole. Upon an increase in pH (to a pH value that is above the pKa value and pH at which the selected chelant will solubilize), the chelant will shed one or more protons (depending on the extent in increase in pH). If the chelant solids were functioning as bridging solids, the increase in pH will cause solubilization of the solids, thereby disrupting any cake formation surrounding the chelant. However, because the pH increase may only occur after the acidic breaker fluid is spent, the solid chelants may first function as bridging solids and/or provide some fluid loss control to the formation during the initial stages of the filter cake breaking. As the pH increases, the chelant strength will likely increase, thus allowing the chelant to function in a second role as a chelating agent, for further filter cake disruption, scale dissolution, scale prevention, corrosion inhibition, etc. The chelant that may be used may be a polydentate chelator such that multiple bonds are formed with the complexed ion, e.g., calcium from the calcium carbonate. Selection of the solid chelant may be based, for example, on the conditional stability constant (the practical expression of the chelate strength of the chelating agent for a certain metal ion) of the chelant and the pH dependence of the conditional stability constant. That is, for a particular ion to be sequestered by the chelant, a chelant having a relatively high conditional stability constant may be used in a pH range in which the conditional stability constant is at its peak. Thus, in particular, the selection of the chelating agent may be related to the specificity of the chelating agent to the particular cations desired to be chelated, the logK value, the optimum pH for sequestering and the commercial availability of the chelating agent, as well as downhole conditions, etc. In one or more other embodiments, the solid chelants of the present disclosure may be incorporated into fracturing fluids, stimulation fluids, or diversion fluids. For example, depending on the formation type, it may be beneficial to use the solid chelants as a solid proppant in a first functionality, and then as a chelating agent, as a second functionality upon an increase in pH, to chelate multivalent cations such as calcium and magnesium often forming some formation types, such as limestone, dolomite, etc. In wellbore stimulation, an acid is often used to clean-up the near-wellbore region as well as to extend perforation tunnels and fractures. Thus, incorporation of the presently disclosed solid chelants may provide an extended clean-up and channel extension upon the acid being spent. One embodiment of the present disclosure provides methods of controlling fluid loss during a fracturing operation that includes injecting a fracturing fluid (base fluid and solid chelants of the present disclosure) into a portion of a subterranean formation at a pressure sufficient to create or extend at least one fracture; allowing the solid chelants to provide fluid loss control in the portion of the subterranean formation; and allowing the solid chelants to solubilize over time in the subterranean formation and thereby reestablish permeability of the portion of the subterranean formation.

[0032] EXAMPLE

[0033] The solubility of several solid chelants were tested using an acidic NaCl brine incorporating a 2:1 ratio of NaCl brine (1.2 SG) and formic acid. To each 9mL volume of the acidic NaCl brine, various quantities of ethylenediamine tetra acetic acid (EDTA), ethylenediamine disuccinic acid (EDDS), and ethylenediamine tetra(methylene phosphonic acid) (EDTMP) were added, the results of which were monitored and are presented in Table 1 below. As observed from the data in Table 1 , the phosphonic acid derivative (EDTMP) shows much lower solubility in a low pH system compared to either EDDS or EDTA.

Table 1

[0034] Another embodiment of the present disclosure provides methods of providing fluid diversion in a subterranean operation that includes introducing a treatment fluid (a base fluid and solid chelants of the present disclosure) into a portion of a subterranean formation at matrix rates wherein the subterranean formation comprises a first zone and a second zone and wherein the first zone is more permeable to the treatment fluid than the second zone; and allowing the solid chelants to seal the rock surfaces along the first zone and thereby divert the treatment fluid to the second zone.

[0035] The present disclosure provides improved methods of providing temporary fluid loss control, fracturing, diversion, etc., in subterranean producing zones penetrated by well bores. The use of the solid chelants of the present disclosure creates a physical barrier to fluid flow (such as by blocking pore throats in a formation or by filling an annulus area) which allows the solid chelant to solubilize over time to remove the physical barrier. The solid chelants dissolve in the presence of a basic aqueous fluid in contact therewith and, once removed, the free movement of fluids within the formation is again allowed, and the chelant is free to chelate polyvalent cations for further well cleanup, scale prevention/dissolution, or corrosion inhibition.

[0036] Although the preceding description has been described herein with reference to particular means, materials, and embodiments, it is not intended to be limited to the particulars disclosed herein; rather, it extends to all functionally equivalent structures, methods and uses, such as are within the scope of the appended claims.

Claims

1. A wellbore fluid comprising:

a solid phosphonic acid-type chelant; and

a base fluid.

2. The fluid of claim 1, wherein the base fluid is an aqueous fluid having a pH of less than 7.

3. The fluid of claim 1, wherein the solid hosphonic acid-type chelant has a formula (I):

wherein each R₂ are independently selected from -P0₃H₂ or a group having a formula

(la):

where n is from 1 to 6.

4. The fluid of claim 1, further comprising at least one acid.

5. The fluid of claim 5, wherein the at least one acid comprises formic acid.

6. A method of performing wellbore operations, the method comprising:

injecting a wellbore fluid into a wellbore, the wellbore fluid comprising:

a solid phosphonic acid-type chelant; and

a base fluid.

7. The method of claim 6, wherein the injecting is performed at conditions at which a filter cake sets up on a surface of the wellbore.

8. The method of claim 6, wherein the injecting is performed at conditions at which the solid phosphonic acid-type chelant blocks pores formed in walls of the wellbore.

9. The method of claim 6, wherein the wellbore fluid is injected during a completion operation.

10. The method of claim 6, wherein the wellbore fluid is injected during a gravel packing operation.

11. The method of claim 6, wherein the wellbore fluid is injected during a fracturing or stimulation operation.

12. The method of claim 6, further comprising:

circulating an acidic breaker fluid.

13. The method of claim 6, further comprising:

initiating flow of hydrocarbons.

14. The method of claim 6, circulating a wellbore fluid into the wellbore, wherein pH of the wellbore fluid increases over time and initiates solubilization of the phosphonic acid-type chelant.

15. The method of claim 6, removing a filter cake from a wellbore wall.

16. The method of claim 6, wherein the solid phosphonic acid-type chelant as a formula (I) below:

wherein each R₂ are independently selected from -P0₃H₂ or a group having a formula (la) below:

where n is from 1 to 6.