Acidificacion Arenas

18-1. IntroductionSandstone matrix acidizing is distinguished from car-bonate acidizing in that it involves the dissolution ofdamage that is blocking or bridging the pore throatsin the formation matrix, thus ideally recovering theoriginal reservoir permeability. Carbonate acidizingdissolves the formation minerals around the damage,creating new permeability. The mineral acids requiredto dissolve the damage are usually highly reactivewith the numerous formation minerals. The resultingchemical complexes can become insoluble in theenvironment created and can precipitate, yieldinggelatinous or solid particles. Because the formationand the damage can have complicated crystallinestructures that can yield a variety of reaction prod-ucts, sandstone acidizing success requires a signifi-cantly better understanding of chemistry than doescarbonate acidizing. As discussed in Chapter 13, 75% of well-engineered sandstone acid treatmentsshould be successful, resulting in significant produc-tion enhancement.

The descriptor “sandstone” is derived from thegeologic classification of rocks with a high quartz sil-ica content. Besides the obvious quartz component,they contain other minerals such as aluminosilicates,metallic oxides, sulfates, chlorides, carbonates andnoncrystalline (amorphous) siliceous material. Theminerals deposited in the original sediment are calleddetrital species. Most have a high degree of associ-ated water. As fluids are produced through the matrixof the rock, the drag forces can move some of theseminerals, clogging the pore throats.

Connate water in a sandstone contains many of thedissolved native mineral species. This is due to equi-librium and partial pressures of gaseous solvents(such as carbon dioxide [CO2]) and the presence ofother ionic species. As fluids are produced, the asso-ciated pressure drop can disturb this equilibrium andthe normal ionic content of the formation brines,resulting in precipitation and possible pore-throatrestriction. This type of diagenesis yields authigenic

species (e.g., scales such as calcium carbonates aswell as some clay species such as zeolites, illites,kaolinites and smectites).

Various well operations can result in formation dam-age (see Chapter 14). For example, drilling mud andcompletion fluid usually penetrate sandstone forma-tions. This invasion of filtrate can introduce an entirelydifferent chemical environment, which the acid treat-ment must address. Additional formation damage mayoccur during perforating, gravel packing, and normalproduction or injection operations. Acid dissolves avariety of damaging materials along with most forma-tion minerals. An understanding of the chemistry isbasic to the selection of the acid type and concentration.

This chapter includes the reaction chemistry of theprimary solvent used in sandstone acidizing, hydro-fluoric acid (HF). Acid systems that contain mixturesof hydrofluoric and hydrochloric acid (HCl) are com-monly called mud acids because they were first usedto remove mud damage.

18-2. Treating fluids

18-2.1. Hydrochloric acid chemistryHCl reactions are discussed in Chapter 17, and detailsof the reaction and by-products are omitted in thischapter except for how they relate to sandstone min-erals. The compatibility of the HF blends used in thisprocess is twofold; these mixtures must meet bothcompatibility standards for the formation mineralogyand dissolution of the damage mineralogy. HF mix-tures are preceded by HCl to avoid precipitation ofthe slightly soluble and insoluble reaction products of HF with certain chemical species. The chemistryof HCl with carbonate minerals is discussed in a pre-vious chapter, so the focus here is on the chemistry of the HF systems. Although the chemistry of thereaction of HCl with carbonate or calcite is simple,the chemistry of the reaction of HF and siliceousminerals is complex.

Reservoir Stimulation 18-1

◆

Sandstone Acidizing

Harry O. McLeod, Conoco, USAWilliam David Norman, Schlumberger Dowell

Some complex reactions that occur with certainsiliceous minerals have only recently been included in the reactions reported in mineralogy breakdowns.These reactions involve HCl and the mineral familyknown as zeolites. Zeolite minerals are crystalline, buthydrated with active, porous channels in the crystallinelattice. Zeolites are known in other industries as “mol-ecular sieves” because their porosity allows the chem-ical extraction and filtering of selective materials.Zeolite minerals occur in nature as a by-product ofvolcanic activity and precipitate from water that isrich in silica. It is theorized that as zeolites areexposed to progressively higher pressures and temper-atures they metamorphose from extremely loose,hydrated crystalline structures to more dense andcompact structures. The results of this process havedifferent mineral names. The hierarchy of their struc-ture and crystalline nature is provided in Table 18-1.Because these minerals are precipitates, they arealways authigenic and located in pore spaces.

Zeolite minerals are sensitive to HCl and strongmineral acids. Several core studies have shown thatthe use of HCl alone causes significant damage,whereas weak organic acid reduces the damage. Theproblem is that the weak organic acid does not neces-sarily remove the damaging mineralogy to restore per-meability. The solution to the problems associated

with zeolites is to recognize the presence of theseminerals before a treatment is performed. The use ofan organic acid as one of two preflush stages and fol-lowing the preflushes with a low-concentration HFmixture that conforms with the remaining minerals in the formation has proved to be highly effective inrestoring permeability and removing damage. All flu-ids that are injected should have an organic acidincluded to maintain a low-pH environment. Someoperators have found the use of an all-organic-acidsystem followed by an organic acid–HF formulationto be effective in high-temperature environments.

18-2.2.Chemistry of hydrofluoric acid systems

HF is the only common, inexpensive mineral acidable to dissolve siliceous minerals. For any acid sys-tem to be capable of damage removal, it should con-tain HF in some form. The most common formulationis simply ammonium bifluoride dissolved in HCl;another is by diluting concentrated HCl-HF formula-tions. The HCl:HF ratio is varied to accommodate thesolubility of the dissolved mineral species present inthe formation. This can be augmented by both pre-flush and overflush acid formulations. Several poten-tial precipitates can be addressed simply by the use of appropriate HCl:HF ratios in the formulations.Numerous mineral species react with HF, and they all generate aluminum silica fluoride complexes(Table 18-2).

• Reactions of hydrofluoric acid with formation minerals

Details of HF reactions with formation mineralshave, for more than 60 years, been known and stud-ied. As early as 1965, it was quantified that 1000 galof 2% HF can dissolve as much as 350 lbm of clay(Smith et al., 1965).

An HCl preflush is always injected in sandstonesprior to the HF. This is done to avoid the possibleprecipitation of insoluble or slightly soluble reactionproducts. Typically, the insoluble species are calciumfluoride (CaF2), which forms on reaction of HF withcalcium carbonate (CaCO3), or sodium or potassiumhexafluosilicates (M2SiF6, where M = Na or K),which result from the reaction of cations in forma-tion brines with solubilized species. The dissolutionof calcium carbonate or magnesium carbonate byreaction with HCl is discussed in detail in Chapter 17.

18-2 Sandstone Acidizing

Table 18-1. The zeolite family.

Mineral Description

Stilbite Hydrous calcium aluminum silicate

Dissolves in contact with HCl; no gelatin formed

Occurs in shallow environments and may occur inside tubulars in silica-rich connate waterformations with high pressure drops

Heulandite Hydrous calcium/sodium/potassium aluminum silicate


Occurs in shallow environments

Chabazite Hydrous calcium/sodium/potassium aluminum silicate


Occurs in medium-depth environments

Natrolite Hydrous sodium/potassium aluminum silicate

Dissolves in contact with HCl; gelatin formed

Occurs in deeper environments

Analcime Hydrous sodium aluminum silicate

Dissolves in contact with HCl; gelatin formed

Occurs in deeper environments

• Stoichiometric equations

Reactions of mud acid with the aluminosilicatecomponents of sandstones are those of HF; how-ever, HF is a weak acid and, because of the equili-brated reaction, is only slightly dissociated whenmixed with HCl:

HF + H2O H3O+ + F–

Ka = 10–3.2 at 75°F [25°C]

where Ka is the acid equilibrium constant.HF can also combine and form complexes, but

this reaction must be taken into account (Fogler etal., 1976) only when the HF concentration is suffi-ciently high (less than 10M) to allow numerouscollisions to occur between the fluoride species.This occurs only in the case of ultra mud acid (25% HCl–20% HF) formulations:

HF + F– HF2–

K = 3.86 at 75°F

The reaction of HF with quartz grains (pure sil-ica) is expressed in the following two equilibria:

SiO2 + 4HF SiF4 + 2H2O

SiF4 + 2F– SiF62–

The intermediate silicon complex, SiF5–, which isnot stable in aqueous solution, is not considered. Thefirst step of silica dissolution consists of the chemi-sorption of the fluoride anion at the silica surface(Iler, 1979). Kline and Fogler (1981b), on the con-trary, showed that it is the molecular HF rather thanthe fluoride anion that adsorbs (see Section 18-4).

Gaseous silicon tetrafluoride usually remains dis-solved in the liquid phase at bottomhole pressure, asCO2 does in the case of carbonate acidization, so theequilibrium is shifted toward the formation of siliconhexafluoride anions and the remaining SiF4 does notrepresent more than 1% of the total dissolved silicon(Labrid, 1971).

Silicon hexafluoride anions can be hydrolyzed fur-ther into monosilicic acid with the evolution of heat:

SiF62– + 8H2O Si(OH)4 + 4H3O+ + 6F–

K = 1.2 × 10–27 at 75°F

When the silicon concentration increases in theaqueous phase, part of the hexafluorosilicate anionsare also transformed into the acidic form of fluosili-cic acid according to the reaction

SiF62– + 2H3O+ H2SiF6 + 2H2O

K = 6.7 × 10–4 at 75°F


Table 18-2. Chemical composition of typical sandstone minerals.

Classification Mineral Chemical Composition

Quartz SiO2

Feldspar Microcline KAlSi3O8

Orthoclase KAlSi3O8

Albite NaAlSi3O8

Plagioclase (Na,Ca)Al(Si,Al)Si2O8

Mica Biotite K(Mg,Fe2+)3(Al,Fe3+)Si3O10(OH)2

Muscovite KAl2(AlSi3)O10(OH)2

Chlorite (Mg,Fe2+,Fe3+)AlSi3O10(OH)8

Clay Kaolinite Al2Si2O5(OH)4

Illite (H3,O,K)y (Al4 ⋅ Fe4 ⋅ Mg4 ⋅ Mg6)(Si8 – y ⋅ Aly)O20(OH)4

Smectite (Ca0.5Na)0.7(Al,Mg,Fe)4(Si,Al)8O20(OH)4 ⋅ nH2O

Chlorite (Mg,Fe2+,Fe3+)AlSi3O10(OH)8

Carbonate Calcite CaCO3

Dolomite CaMg(CO3)2

Ankerite Ca(Fe,Mg,Mn)(CO3)2

Siderite FeCO3

Sulfate Gypsum CaSO4 ⋅ 2H2O

Anhydrite CaSO4

Chloride Halite NaCl

Metallic oxide Iron oxides FeO, Fe2O3, Fe3O4

This transformation is usually limited, becausefluosilicic acid is a strong acid. Aluminosilicateminerals generally have complex chemical compo-sitions, such as those listed in Table 18-2. Theiroverall dissolution reactions thus involve manysimple equilibria.

The disintegration of aluminosilicate minerals byHF can be considered stoichiometric as a first step;i.e., the Al:Si ratio is the same in the solution as inthe mineral. Silicon is solubilized by the same pro-cess mentioned for quartz, whereas aluminum isinvolved in several fluorinated complexes:

AlFn(3 – n )+ AlFn

(4 – n )+ + F–

where 0 ≤ n ≤ 6.The prominent form of aluminum complexed

varies as a function of the free fluoride ion concen-tration: the average ratio of fluorine to aluminumdecreases as the dissolution reaction progresses(fewer fluoride anions are available), as shown in Fig. 18-1 (Labrid, 1971).

The dissolution reaction of all aluminosilicateminerals in sandstones follows the previous equa-tions for the basic lattice atoms (Si, Al) concerned.Other metallic ions, such as Na, K, Mg, Ca and Fe,which are in the minerals constituting the rock assubstitution cations in the lattice or as exchangeable(adsorbed) cations, come into solution as free ionsduring the reaction. In the case of iron, fluorinatedcomplexes (FeFz

(3 – z )+, where 1 < z < 3) also areformed through reactions similar to those for alu-minum. Thus, different global reactions can bewritten as a function of the considered mineral:

– Kaolinite clay

Al4Si4O10(OH)8 + 4(n + m) HF + (28 – 4(n + m))H3O+

4AlFn(3 – n )+ + 4SiFm

(4 – m )– + (46 – 4(n + m))H2O

– Sodic or potassic feldspar

MAlSi3O8 + (n + 3m)HF + (16 – n – 3m)H3O+

M+ + AlFn(3 – n )+ + 3SiFm

(4 – m )–

+ (24 – n – 3m)H2O

where 0 ≤ n < 6 and m = 4 or 6.

18-3. Solubility of by-productsWhen minerals are dissolved by HF, numerous by-products can form. Some potential precipitates arelisted in Table 18-3. In many cases, the increase in theliquid-phase pH value resulting from acid mixturespending constitutes the driving force for precipitateformation; therefore, precipitation can be predictedfrom consideration of the sole liquid phase. The extentof precipitation should always be limited. If this is notpossible, the potential precipitation zone that wouldcause a decrease in permeability should be diluted anddisplaced from the wellbore (Walsh et al., 1982).

Should precipitation occur, most of the calcium andsodium complexes that precipitate in the field can beredissolved by using boric acid. This is not true, how-ever, for potassium and some of the magnesium com-plexes. The very low solubility of potassium complexeshas been shown both in the laboratory and in the field.

Colloidal silica precipitation cannot be avoided, asit results partly from the greater affinity of fluorine for


Figure 18-1. Domains of existence of aluminum-fluorinecomplexes (Labrid, 1971).

AIF

con

cent

ratio

n (%

) 100

50

10–4 10–3 10–2

Fluoride ion concentration (g ion ⁄ L)

AIF5

AIF4

AIF3

AIF2

AIF

Table 18-3. Solubility in water at room temperature of HF reaction by-products.

Secondary Product Solubility (g/100 cm3)

Orthosilicic acid (H4SiO4) 0.015

Calcium fluoride (CaF2) 0.0016

Sodium fluosilicate (Na2SiF6) 0.65

Sodium fluoaluminate (Na3AlF6) Slightly soluble

Potassium fluosilicate (K2SiF6) 0.12

Ammonium fluosilicate ((NH4)2SiF6) 18.6

Calcium fluosilicate (CaSiF6) Slightly soluble

Aluminum fluoride (AlF3) 0.559

Aluminum hydroxide (Al(OH)3) Insoluble

Ferrous sulfide (FeS) 0.00062

aluminum than for silicon. This process acceleratesthe hydrolysis of SiF6 because the released F– anionsare further involved in aluminum complexes and moremonosilicic acid (Si(OH)4) is generated. Certainauthors (Labrid, 1971; Shaughnessy and Kunze, 1981;Walsh et al., 1982) have emphasized the highly dam-aging potential of the precipitation of colloidal silicain a porous medium; however, this damaging actionhas never been demonstrated clearly and satisfactorily.

On the contrary, other authors (Crowe, 1986)showed that such “precipitation” is actually the resultof a topochemical reaction (exchange of fluoride fromthe hexafluorosilicate anion occurs with aluminum onthe surface of the silt and clay), and it does not inducedamage.

Precipitation begins earlier in the dissolution processat higher temperatures (within 10 min at 200°F [95°C])because of the increased thermal agitation. It alsooccurs more quickly in montmorillonite-type clays than in kaolinite clays because of the different initial Al:Siratios in these minerals (molar ratio of 1 for kaoliniteand less than 0.5, depending on the substitution extent,for montmorillonite). Finally, aluminum can be totallyremoved from clays, with a correlated silica depositionat the surface (topochemical reaction).

18-3.1. Calcium fluorideSome carbonates may remain after preflushing, eitherbecause of the initial amount of carbonate cementingmaterial in the sandstone or as a result of the carbon-ates’ initial protective siliceous coating. Also, slightlysoluble, fine crystalline CaF2 readily forms when cal-cite contacts HF. This can lead to substantial damage:

CaCO3 + 2HF CaF2 + H2O + CO2

Where this precipitate has formed but has not com-pletely blocked the porosity of the formation, it maypartially redissolve when HF is near complete spend-ing toward the end of the job. At this time, the con-centration of fluoride anions in solution is so low thataluminum is hardly complexed and appears mainly asfree Al3+ ions (Labrid, 1971). These aluminum ionsare then able to extract fluorine from the CaF2 precipi-tates, as they did for silicofluorides, and partly redis-solve the CaF2 according to the reaction

3CaF2 + 2Al3+ 3Ca2+ + 2AlF2+

This reaction may be followed by subsequent equilibriabetween the different aluminum and fluorine complexes.

18-3.2. Alkali fluosilicates and fluoaluminates

The aluminum or silicon fluorine complexes can reactwith alkali ions released in the solution from highlysubstituted clays or alkali feldspars as soon as theirconcentration becomes sufficiently high to form insol-uble alkali fluosilicates and, probably, fluoaluminates:

2Na+ + SiF62– Na2SiF6 Ks = 4.2 × 10–5

2K+ + SiF62– K2SiF6 Ks = 2 × 10–8

3Na+ + AlF3 + 3F– Na3AlF6 Ks = 8.7 × 10–18

2K+ + AlF4– + F– K2AlF5 Ks = 7.8 × 10–10

where Ks is the solubility constant.Alkali fluosilicate precipitation is favored by a high

level of HF. Fluosilicate precipitates, which form fromthe attack of mud acid on alkali feldspars or clays, arewell crystallized and very damaging (Bertaux, 1989).These damaging precipitates also form when the vol-ume of preflush is insufficient and HF contacts forma-tion brine containing alkali ions.

18-3.3. Aluminum fluoride and hydroxideAluminum fluoride (AlF3) or aluminum hydroxide(Al(OH)3) in the gibbsite form can precipitate uponspending of the acid. The precipitation of AlF3 can bereduced by maintaining a high proportion of HCl toHF (Walsh et al., 1982). These precipitates formaccording to the reactions

Al3+ + 3F– AlF3

Al3+ + 3OH– Al(OH)3 Ks = 10–32.5

18-3.4. Ferric complexesThis mechanism of forming iron fluorine complexesapplies only to relatively clean sandstones. In the pres-ence of clays, the dissolved aluminum ions have agreater affinity for fluorine than iron does. Therefore,the iron fluorine complexes do not form and ironhydroxide still precipitates at pH levels greater than 2.2.

The nature of the precipitate (crystalline or amor-phous) varies as a function of the anions present(Smith et al., 1969). Ferric hydroxide can be stronglybound to the quartz surface by electrostatic interac-tions because its point of isoelectric charge is above a pH value of 7. In the presence of excess calcite, the


dissolved CO2 can also lead to the precipitation ofinsoluble ferric carbonates (siderite or ankerite).Chapter 15 provides additional information about ironcontrol and solutions for problems.

18-4. Kinetics: factors affecting reaction rates

This section summarizes qualitatively the resultsdescribed in detail in Chapter 16. Because theoreticalaspects are covered in Chapter 16, only the practicalimplications are discussed here.

Kinetically controlled reactions (surface reaction limit-ed) are effective during the acidization process of sand-stones, and factors affecting reaction rates are discussedto complete previous thermodynamic considerations.

18-4.1. Hydrofluoric acid concentrationDissolution reaction rates are proportional to the HFconcentration (Fogler et al., 1976; Kline and Fogler,1981b) for most sandstone minerals, except smectite.This explains why formations with low competence(i.e., weak cementation, potentially mobile fine parti-cles) should be treated with a reduced-strength mudacid (1.5% HF) to avoid crumbling, especially at bot-tomhole temperatures greater than 200°F. Fluoboricacid performs similarly because of the low concentra-tion of HF present at any time.

18-4.2. Hydrochloric acid concentrationDissolution reaction rates generally increase in a moreacidic medium because the leaching of constitutivesurface cations involves their replacement by protons,but the dependence on HCl concentration is notstraightforward (Gdanski and Peavy, 1986). The prin-cipal role of HCl is to prevent secondary precipitationby maintaining a low pH value. The other main effectof HCl is to catalyze the attack of sandstone mineralsby HF. The mechanism and degree of catalysis dependon the type of mineral, as shown in the following.

For example, the reaction rate measured at 95°F[35°C] for pure quartz has the following expression(Fogler et al., 1976):

(18-1)

in mol quartz/cm2/s.

In the case of a feldspar with the overall formula Na 0.72K 0.08Ca 0.2Al1.2Si 2.8O8, the followingexpression has been determined (at 75°F under 275-kPa pressure) as the reaction rate (Fogler et al., 1976):

(18-2)

in mol feldspar/cm2/s.An elemental mechanism proposed to explain the

previous variation involves the adsorption of protonson the surface that weakens the siloxane bondings,which is followed by the reaction of HF moleculesthat creates unstable silicon-fluorine bonds at the sur-face, according to the scheme

H

–X–O–Si– +H+ → –X–O…Si+– + HF →–X + FSi– + H2O

where X = Al or Si.This is the acid (proton) catalysis mechanism pro-

posed by Kline (1980) for feldspar.The dissolution reaction is a first-order reaction

with respect to the HF concentration for most alumi-nosilicate minerals. Nevertheless, dissolution kineticsis better represented by a Langmuir-Hinshelwood–type law in the case of sodium montmorillonite (Klineand Fogler, 1981):

(18-3)

where Kads is the equilibrium constant of the exother-mic adsorption of HF molecules at surface-reactivesites. This adsorption constant is independent of thetotal acidity, whereas K increases with proton concen-tration (acid catalysis). Kads is especially high for amineral with a high cation exchange capacity (CEC),such as sodium montmorillonite. For most other clayminerals, the value of this adsorption constant issmall. Therefore, when 1 >> Kads[HF] the expressioncan be simplified to the experimentally determinedfirst-order kinetics law. An elemental mechanism dif-ferent from that mentioned for feldspars can be pro-posed to explain the kinetics and to take into accountsolely the HF adsorption:


rquartz = × + [ ]( )[ ]− +9 2 10 1 0 89. . H HF

rfeldspar = × + [ ]( )[ ]− +1 3 10 1 0 49. . H HF

RKK

Kads

ads

= [ ]+ [ ]

HFHF1

,

F

HO OH HO H OH HO OH

–X–O–X– +HF –X–O–X– –X –F + HO–X–

where X = Al or Si.

18-4.3. TemperatureThe dissolution of minerals is a thermally activated phe-nomenon; thus, the rates increase greatly as a function oftemperature (approximately multiplied by 2 for quartzfor a 25°C increment), and the penetration depths of liveacid diminish accordingly. In the case of quartz, the acti-vation energy is about 5.2 kcal/mol, and in the case ofthe previous feldspar, it is about 8 kcal/mol (Fogler et al., 1976).

Figure 18-2 shows the variation of the reaction rateof mud acid with vitreous silica (more reactive thanquartz) as a function of both HF concentration andtemperature (Smith and Hendrickson, 1965). Alumi-num and iron solubilities also increase slightly with a rise in temperature.

18-4.4. Mineralogical composition and accessible surface area

The relatively high total specific surface area of sand-stone rocks is the primary parameter determining mudacid spending because of the heterogeneous nature ofthe dissolution reaction. However, if the contribution

of each mineral to the total accessible surface area isconsidered, great discrepancies between the reactionrates of pure phases can be predicted and observed(Table 18-4).

Clays react much faster than feldspars, which reactmuch faster than quartz, especially in the presence of highproton (H+) concentrations. Thus, most of the quartzmatrix (about 95%) can be considered inert with respectto the dissolution reaction, and the mineralogical nature of the accessible rock components determines the overallreaction rate. This situation also emphasizes the necessityof HCl preflushes and excess HCl in the HCl-HF mixture.Calcite reacts at the highest rate of all the minerals thatcan be present in a sandstone, leading to HF microchan-neling, but the mechanism of attack is not comparablebecause protons coming from either HCl or HF can pro-voke the dissolution.

18-4.5. PressureAn increase in pressure speeds up the overall dissolutionreaction slightly, because dissolved silicon tetrafluoridecan be transformed partially into an acidic species(H2SiF6) and can quickly initiate further reactions. Forquartz, a 24% rise in the reaction rate was noticed between the two extreme conditions (Smith et al., 1965).

In a radial injection situation, the mineral pore-space texture that determines flow partition around thewellbore (most live acid flows through the largepores) is also a relevant parameter; clay clasts can be bypassed by the acid flow (Williams, 1975).

18-5. Hydrofluoric acid reaction modeling

The parameters that affect the reaction rate of HF onsandstone minerals are incorporated in a model that


Figure 18-2. Reaction rate of HCl-HF on silicate glass(Smith and Hendrickson, 1965).

Rea

ctio

n ra

te (l

bm ⁄

ft2 /

s ×

10–6

)

7

6

5

4

3

2

1

00 1 2 3 4 5 6 7 8 9 10

HF (%)

Reaction time, 60 min

125°F150°F

175°F

Table 18-4. Relative surface areas of sandstone minerals.

Mineral Surface Area

Quartz <0.1 cm2/g

Feldspar Few m2/g

Kaolinite 15–30 m2/g

Illite 113 m2/g

Smectite 82 m2/g

predicts the evolution of formation parameters whenacid is injected.

In terms of surface reaction rates, sandstones aretypically considered a two-component system:

• slow-reacting pseudocomponent, forming the crys-talline quartz fraction

• fast-reacting pseudocomponent, comprising allother species (e.g., clays, feldspars and poorlycrystallized silica).

For both pseudocomponents, the overall kinetics,which includes the diffusion of HF-reactant species tothe surface, surface reactions and the diffusion of react-ed products back to the bulk solution, is governed bythe surface reactions because they are the slowest step.Therefore, matrix acidizing of sandstones with HF iscalled surface reaction limited.

This is the major difference from the matrix acidiz-ing of limestone, where the process is diffusion con-trolled. In sandstones, the increase in permeabilityresults from damage removal and is correlated with a small increase in rock porosity. Quartz reacts veryslowly with HF; reactions with most aluminosilicatesprovoke a rapid spending of the acid. A pseudo-stationary state reflects the much faster variation inspecies concentration (chemical modifications) thanthe one within the rock porosity (resulting in physicalmodification). The HF progresses and homogeneouslydissolves every pore and never forms conductivechannels or wormholes. The flow is stable, and sharpfronts are formed in response to the dissolution of dif-ferent mineral species as acid injection progressesradially (McCune et al., 1975).

Several authors have tried to model this process.Taha et al. (1986) used the reaction model developedby Fogler and various coworkers (see particularlyHekim et al., 1982). Such a simplified, two-pseudo-component model and macroscopic description can beused because Fogler et al. (1976) showed that the orderof reaction of HF with each pseudocomponent is equalto unity relative to the concentrations of HF and of thepseudocomponent. The flow is considered stable.

In this model the mineral dissolution fronts can becomputed and the concentration of remaining clays(or fast-reacting materials) can be calculated. Then,the permeability increase can be estimated from thechange in porosity (or amount of material dissolved).The velocity of the mineral dissolution front dependson the acid capacity number Ac, which is a function of

the volume of clays (or fast-reacting dissolvable mate-rial) and of the acid concentration.

The acid concentration (or spending) front can bemodeled similarly. The thickness of the front dependson the Damköhler number Da, which is a function ofthe reaction rate and the acid velocity. These simula-tions show why HF does not penetrate deeply into thereservoir before spending unless unrealistically largevolumes are used. (These large volumes would almostdissolve everything around the wellbore and thusleave the reacted formation totally unconsolidated.)

18-6. Other acidizing formulationsProblems related to the use of mud acid to removedamage in sandstone formations include the following:

• Rapid spending provides only a short penetration,especially at high temperatures (maximum depthabout 12 in.).

• Fines, composed of either mostly quartz or mostlyclay minerals, can be generated during the acidreaction and can migrate with the fluid flow. Thedestabilization of fines can lead to a quick produc-tion decline after treatment. Gravel-packed gaswells can exhibit a 50% productivity reduction.

• The high dissolving power of mud acid destroysrock integrity at the formation face.

New sandstone acidizing systems are designed toalleviate these shortcomings.

18-6.1. Fluoboric acidFluoboric acid is recommended by Thomas andCrowe (1981) as an alternative to mud acids. It doesnot contain large amounts of HF at any given timeand thus has a lower reactivity. However, it generatesmore HF, as HF is consumed, by its own hydrolysis.Therefore, its total dissolving power is comparable toa 2% mud acid solution. Fluoboric acid solutions areused as a preflush before treating formations sensitiveto mud acid; this avoids fines destabilization and sub-sequent pore clogging. They are also used as a soletreatment to remove damage in a sandstone matrixwith carbonate cement or in fissures that contain manyclay particles. Another use is as an overflush after amud acid treatment that has removed near-wellboredamage (up to 0.5 ft) to allow easier penetration of the


fluoboric acid solution (a few feet). Fluoboric acid isrecommended when the sandstone contains potassicminerals to avoid damaging precipitates and in thecase of fines migration owing to its fines stabilizationproperties.

In the field, fluoboric acid is easily prepared bymixing boric acid (H3BO3), ammonium bifluoride(NH4F ⋅ HF) and HCl. Ammonium bifluoride, anacidic salt of HF, reacts first with HCl to generate HF:

NH4F ⋅ HF + HCl → 2HF + NH4Cl

Tetrafluoboric acid is formed as a reaction productof boric acid with HF, according to

H3BO3 + 3HF → HBF3OH + 2H2O (quick reaction)

HBF3OH + HF HBF4 + H2O (slow reaction)

Hydroxyfluoboric acid (HBF3OH) probably does notexist in aqueous solutions unless it is in equilibriumwith fluoboric acid (Wamser, 1948). The precedingslow reaction is of an order equal to unity with respectto both HF and HBF3OH. For this reaction, equilibriumis attained at room temperature after nearly 40 min fora resulting lM HBF4 solution. Because the equilibriumconstant at 75°F is K = 2.3 × 10–3 (Wamser, 1948),about 6% (molar) HBF4 is converted into HBF3OH atequilibrium for a lM HBF4 solution. These equilibriumconsiderations mean that at any given time and placethere is only between 0.1% and 0.2% (weight) of freeHF at ambient temperature and 212°F [100°C], respec-tively.

Fluoboric acid is a strong acid with strength compa-rable to that of HCl (Maya, 1977); thus, the followingreaction occurs in solution:

HBF4 + H2O → H3O+ + BF4–

In the following text, reactions are written using BF4–

instead of HBF4. Acid strength diminishes in the fol-lowing order: fluoboric, hydroxyfluoboric (the strengthof which can be compared to that of trichloroaceticacid; Maya, 1977) and boric acid (KH3BO3

= 9.2 at75°F).

The dissolving power of fluoboric acid results fromthe generation of HF through its hydrolysis:

BF4– + H2O BF3OH– + HF

The BF3OH anions can be further hydrolyzed suc-cessively into BF2(OH)2

–, BF(OH)3– and H3BO3 with

correlated HF formation, but these reactions must betaken into account only when the BF3OH– concentra-tion is lower than 3 × 10–3 at 75°F (Wamser, 1948). In

the following text, BF3OH– hydrolysis is neglected atthe usual acid concentrations.

The hydrolysis reaction kinetics of fluoborate ionsis affected by

• concentration of the fluoborate ions

• medium acidity, which has a catalyzing effect (reac-tion is proportional to the proton concentration)

• temperature, through the usual activation energyeffect.

Thus, the reaction rate, assuming the reverse reac-tion is negligible, can be expressed after Kunze andShaughnessy (1983) as

(18-4)

where

in (mol/L)–1min–1 and T is the temperature in kelvin.Thus, the reaction rate is increased 300-fold when the

mixture is heated from 75° to 150°F [25° to 65°C] andis increased 12,000-fold when heated from 75° to 220°F[105°C]. Because the hydrolysis reaction kinetics is not affected by clays, fluoboric acid can be considered a retarded acid in normal use (i.e., less than 200°F). Inthe presence of excess bentonite, pure 0.1M fluoboricacid is spent within 30 min at 150°F (Kunze andShaughnessy, 1983). In a slurry test, which has an infi-nite surface area (1 L of acid with 20 g of bentonite or1600 m2 of surface area, which is equivalent to severalfootball fields of exposed area), the reaction rate is afunction of the rate of hydrolysis. However, in thematrix, where there is a finite amount of clay surface,the reaction rate is a function of the amount of HF pres-ent, which in the case of fluoboric acid is low.

The reaction of fluoboric acid in sandstonesinvolves at the same time the hydrolysis reaction offluoboric acid, standard reactions of the generated HFwith minerals and additional slow reactions related tothe fluoborate ions in the liquid phase. As expected,the dissolution reaction of clays with fluoboric acid is a first-order reaction with respect to the fluoborateconcentration, similar to the relation of the reaction of mud acid to the HF concentration.

The spending rate of fluoboric acid on glass slidesat 150°F is one-tenth that of a mud acid with the sametotal HF content (Thomas and Crowe, 1981). Amor-


rd

dtK= [ ] = [ ][ ]

−+ −BF

H O BF43 4 ,

KT

= × −

1 44 1026 1831 987

17.,

.exp

phous silica reacts faster than quartz, which limits thedestruction of cores near the injection face during flowtests with fluoboric acid. Significantly less destructionis noted than during mud acid flow testing. Thereduced destruction with fluoboric acid results in 30%to 50% higher compressive strengths than observedfor mud acid.

The unique advantage of fluoboric acid is that it pro-vides efficient stabilization of clays and fines throughreactions related to borate and fluoborate ions. Swellingclays are desensitized by fluoboric acid, and there is alarge decrease in the CEC (e.g., a 93% decrease after18 hr in fluoboric acid at 150°F for a Wyoming ben-tonite was observed by Thomas and Crowe).

After a fluoboric acid treatment, migrating claysand other fines stabilize as a result of the rock’s expo-sure to acid. This is why a long shut-in time is recom-mended in fluoboric acid treatments. During injection,while the acid spends normally, cores treated onlywith fluoboric acid exhibit a normal increase in per-meability. However, no long-term stabilization occursafter treatment because only a portion of the clay wasdissolved; the remainder did not have time to stabi-lize. Additional shut-in time allows this stabilization.

When treated by fluoboric acid, montmorillonite pro-gressively decreases in aluminum content and then pro-gressively incorporates boron atoms; silicon precipitatesfrom the solution. Cores originally containing 30% sili-coaluminates at 150°F attain maximum static solubili-ties after only 24 hr in the presence of lM HBF4 (4 hrfor mud acid), whereas the maximum increase in per-meability is obtained after only 4 hr under dynamicconditions (Thomas and Crowe, 1981). These resultsprove the dissociated effects of mineral dissolution bythe generated HF (essentially kinetically controlled) andof particle stabilization resulting from the slow complexdissolution/reprecipitation mechanisms (toward thermo-dynamic equilibrium) during the shut-in period.

Examination under a scanning electron microscope(SEM) shows that the original kaolinite clay platelets—pure aluminosilicates—that are not dissolved by fluo-boric acid appear welded together and to the quartzgrains. A type of chemical fusion of any fines seems totake place slowly onto the silica surface. The formationof borosilicate “glass” has been assumed to account forthis reaction.

Bertaux (1989) observed that in silicoaluminates con-taining potassium, such as illite, potassium fluoborateforms after treatment with fluoboric acid as a nondam-aging coating on the clay; potassium hexafluosilicate

forms after treatment with mud acid. This shows thatnondamaging by-products are formed by fluoboric acid,whereas formation plugging by alkali fluosilicates canoccur with mud acid. This is another advantage of usingfluoboric acid in some “acid-sensitive” formations.

During the injection period, fluoboric acid behaveslike a weak HF solution, but one in which the HF isconstantly replenished. The small amount of fluorideions available at any time limits the danger of precipi-tating aluminum species. Only the first acidity is usedduring this step. Hydroxytrifluoboric acid (HBF3OH)buffers the solution and prevents other undesirableprecipitations.

During shut-in, HBF4 and HBF3OH continue toreact, but at a slow pace because the hydrolysis isminimal. The liberated HF reacts further with mineralspecies. It also reacts by topochemical reactions, inwhich the aluminum from the undissolved clay struc-ture is put into solution by forming one of the fluoalu-minate complex ions (depending on F–), and thesurface of the mineral is therefore enriched in siliconand boron. An amorphous coating of silica and boro-silicate glass is then formed over the remaining silicateand fine silica grains, welding them to the frameworkand thus preventing their migration.

This effect is clearly seen in Figs. 18-3 and 18-4,where the same pore, containing two different clays(kaolinite and illite), is shown before and after reac-tion with a fluoboric acid solution. The quartz isbarely etched, whereas the high-surface-area, fast-reacting illite is completely dissolved. The kaoliniteplatelets are about half-dissolved, and an amorphousmaterial is coating the undissolved kaolinite, weldingthem together and to the underlying quartz grain.

18-6.2. Sequential mud acidThe sequential mud acid system involves the in-situgeneration of HF, occurring from the alternate injec-tion of HF and ammonium fluoride (Hall et al., 1981).The reactions of HF are thought by some to take placeat the rock surface by adsorption followed by ionexchange, but the yield of this heterogeneous processseems highly doubtful for several reasons:

• If HF were generated through such a process, itwould be a small quantity, hardly enough to etchthe surface of the clay material.

• Because this process is based on the CEC of theclays, migrating kaolinite would hardly be touched.


• This process supposes the initial adsorption of thehydronium (H3O+) ions on the clay surface, fol-lowed by their exchange with NH4

+, to generate HFin situ. Exchange and replacement of H3O+ by NH4

+

depends on many parameters and cannot be ascer-tained. Therefore, even the generation of HF isdubious.

18-6.3. Alcoholic mud acidAlcoholic mud acid formulations are a mixture ofmud acid and isopropanol or methanol (up to 50%).The main application is in low-permeability dry gaszones. Dilution with alcohol lowers the acid-mineralreaction rate and provides a retarding effect.

Cleanup is facilitated; acid surface tension isdecreased by the alcohols while the vapor pressure of the mixture is increased, which improves gas perme-ability by reducing water saturation.

18-6.4. Mud acid plus aluminum chloride for retardation

An acidizing system to retard HF-mineral reactions hasbeen proposed in which aluminum chloride (AlCl3) isadded to mud acid formulations to complex some ofthe fluoride ions in the injected mixture, according tothe reactions (Gdanski, 1985)

AlCl3 + 4HF + H2O AlF4– + 3HCl + H3O+

AlF4– + 3H3O+ AlF2

+ + 3HF + 3H2O

This procedure is tantamount to adding dissolutionreaction products to the mixture before the reactionsoccur (i.e., the injection of spent acid). In theory thisshould slow the rates. However, the retardation of claydissolution has not been proved experimentally becauseof the prime importance of the high surface area onclay reactivity, which is much more important than aslight depletion of acid at high temperatures. The riskof early precipitation of damaging products, such asAlF3 or fluoaluminates, is probably increased by the useof an acid that already contains aluminum ions beforereaction. Flow tests have shown a smaller effective liveacid penetration than in the case of mud acid. In addi-tion, field experience has shown that the addition ofaluminum to the system increases the precipitation ofamorphous aluminosilicate scale. This white materialplugs near-wellbore perforations and gravel packs.

18-6.5. Organic mud acidBecause total acidity speeds mineral dissolution withmud acid, organic mud acid involves replacement ofthe 12% HCl component with organic acids (9%formic acid, a weak acid that only partially dissoci-ates), mixed with 3% HF, to retard HF spending. Thissystem is particularly suited for high-temperaturewells (200° to 300°F [90° to 150°C]), for which pipecorrosion rates are diminished accordingly. This sys-tem also reduces the tendency to form sludge.


Figure 18-3. SEM photograph of kaolinite (K) and illite (I)clays in a pore (Q = quartz), before attack.

Figure 18-4. SEM photograph of the same pore after an 8%HBF4 treatment.

18-6.6. Self-generating mud acid systemsSelf-generating acidizing systems were originallydeveloped by Templeton et al. (1975), and their appli-cation was widened by Abrams et al. (1983). Theyinvolve the hydrolysis of organic esters into the corre-sponding carboxylic acids, followed by the reaction ofthese acids with ammonium fluoride to yield HF.Because the hydrolysis reaction is activated by tem-perature and the acidity obtained is not as strong aswith mud acid, a low corrosion rate of tubular goodsand delayed reaction of the progressively generatedHF are expected. The latter would allow deep penetra-tion of live HF.

Depending on the bottomhole temperature, differentorganic esters are used:

• methyl formate between 130° and 180°F [55° and80°C] with the reactions

HCOOCH3 + H2O HCOOH + CH3OH

HCOOH + NH4F NH4+ + HCOO– + HF

(the latter is the slow, rate-controlling reaction).

• ammonium salt of monochloroacetic acid between180°F and 215°F [102°C]:

NH4+ + ClCH2COO– + H2O

HOCH2COOH + NH4+ + Cl–

• methyl acetate between 190° and 280°F [90° and140°C].

The reagent choice is intended to limit at 30%(maximum) the generation of HF during pumping ofthe mixture in the tubing; thus, a minimum of 40 minof spending time seems necessary. However, fieldtests of these systems have not been conclusive. Manyprecipitates form in these low acidic systems, such asralstonite (NH4MgAlF6) and other fluoaluminates(silicates) upon spending of these mixtures on clays;thus, the use of complexing agents or acids, such ascitric acid, is suggested. Furthermore, formation sensi-tivity after treatment has not been tested, and handlingproblems arise from the high flammability of methylformate.

Overall, these systems have many drawbacks. Basedon the hydrolysis of various organic esters, they aretemperature activated. Unlike fluoboric acid, whichgenerates new HF only upon spending, no equilibriumis reached. This means that more HF is generated as thetemperature increases, and the ester can eventually becompletely hydrolyzed long before reaching the final

depth of damage. The true degree of retardation dependson the temperature and pumping time. These esters aremore expensive and more dangerous to handle becauseof their flammability than HCl or inorganic salts. Moreprecipitates are formed as a result of the poor solubilityof the organic by-products. The only advantage overreduced-strength HF is lower corrosion rates.

18-6.7. Buffer-regulated hydrofluoric acid systems

Other high-pH acidizing systems proposed for use up to 360°F [180°C] involve the buffering effect of an organic acid and its ammonium salt, mixed withammonium fluoride, as an HF precursor (Abrams etal., 1983). To minimize corrosion, the use of the sameuninhibited buffer without ammonium fluoride as apreflush has been recommended up to 350°F [175°C].The ammonium salt of the organic acid is generatedfrom the partial neutralization of the acid with ammo-nium hydroxide. The proposed buffered systems are

• formic acid/ammonium formate with pH = 3.5 to 4

• acetic acid/ammonium acetate and citric acid/ammonium citrate with pH = 4.5 to 5.

To extend the application to higher temperatures (up to 550°F [290°C]), an excess of ammonium salt is formed by using a higher ratio of ammoniumhydroxide to organic acid. Because the kinetics of claydissolution increases with the fluoride ion concentra-tion, more ammonium fluoride is added to compensatefor the pH increase (Scheuerman, 1988). Successful in-depth stimulation has been observed with this systemonly for bottomhole temperatures lower than 129°F[54°C]. In most cases using this system, many damag-ing precipitates are noticed (e.g., fluosilicates, fluoalu-minate usually involving ammonium), the formation of which is related to the weak acidity in the near-wellbore area. These systems suffer from the samedrawbacks as the self-generated mud acid system.

18-7. Damage removal mechanismsSelection of a chemical as a treatment fluid for anyapplication depends on the contaminants plugging theformation. HCl does not dissolve pipe dope, paraffinor asphaltenes. These solids or plugging agents areorganic in nature, and their treatment requires aneffective organic solvent (usually an aromatic solvent


such as toluene, xylene or orthonitrotoluene). Becausedifferent plugging solids require a variety of solventsfor their removal, there is no universal solvent forwellbore damage. The proper evaluation of damageand treatment design are illustrated by Clementz et al.(1982) for the successful removal of bacterial damagein water injection wells. Solvent or acid should neverbe pumped into a well until the probable causes ofdamage and the best chemical to remove the damagehave been defined.

Compatibility with formation fluids and mineralogyis extremely important in sandstone acidizing. Thus,determination of the precipitation potential of mudacid mixtures requires close scrutiny of the mineral-ogy and connate water present. Acid reaction productsare not necessarily soluble in the spent solution or incertain ionic environments.

Formation damage is fully discussed in Chapter 14.

18-7.1. Formation response to acidIncompatibilities may occur even if the damage isidentified, an appropriate removal fluid system isavailable and the probable response of the formationfluids and minerals to the acid and spent acid solutionhas been determined. These incompatibilities canresult in solid or gelatinous precipitates, which canplug pores and offset the improvement the acid wasintended to create. Results can range from no harmfuleffects and complete cleanup of the damage to lessthan optimum improvement or plugging of the forma-tion with acid-generated precipitates.

When detailed petrographic core analyses are avail-able, geochemical simulators can be used to estimatepotential problems. This type of simulation requiresdetailed definition of the chemistry of the treatingfluid, formation damage and matrix mineralogy. Therelease of fines and undefined spent-acid precipitatesstill have the potential to damage the formation andare not identified by core testing.

18-7.2. Formation propertiesDamage prevention and dealing with formation responsebefore acidizing are the goals of proper design. Althoughit may be easy to dissolve formation damage, success isdependent on dissolving this material without damagingthe formation. This is possible, yet it is paramount todefine the chemistry of the formation minerals and treat-

ing fluids to predict how the spent acid will react as itpenetrates the formation. Potential incompatibilities canbe prevented by proper log and core evaluation. Becausethe secondary reactions can be just as damaging, definingthe potential problems generated by long-term exposureshould also be evaluated.

Two key formation characteristics for fluid selectionare mineralogy and permeability. Defining formationmineralogy helps to confirm the types of acid systemsand acid concentrations to use. Defining formationpermeability provides the information required to esti-mate the matrix injection rate and the maximumbottomhole pressure allowed before hydraulicallyfracturing the formation.

Pore pressure, temperature and the mechanical condi-tion of the formation are influential in the design. High-pore-pressure formations fracture at much lower pressuredifferentials than depleted formations. Depleted forma-tions have a lower fracture pressure than that originallyobserved. Temperature significantly affects the selectedfluid’s reaction rate with different mineral types. Acidconcentrations are usually lower for higher temperatures.The mechanical integrity of the formation biases the fluidselection in that the acid concentrations are usuallyreduced in less consolidated formations.

18-7.3. Formation brine compatibilityCompatibility with formation brines must be consideredwhen treating with mud acid. Mud acid mixtures canform CaF2 (a solid) when excess Ca2+ ions are present.Similar solid materials are also created with K+ and Na+

ions. The use of clear brines as completion and work-over fluids has increased the necessity of checking theformation waters for compatibility. This brine usage hasalso increased the necessity of ensuring that sufficientcompatible preflush is used to dilute and remove theseionic species prior to injection of the mud acid system.Several available methods have been tested. The salinityof the connate brine is in equilibrium with the nativeminerals and their CEC. When possible, the salinity ofthe preflush and overflush fluids should closely approx-imate that of the connate brine. Historically, the use oflow-salinity brines has rarely presented catastrophicproblems when used in conjunction with acid treatments.

Several additives have been demonstrated to posi-tively affect the formation’s sensitivity to changes insalinity. Other species in connate water have equal, if not more, influence on the success of the treatments.


Each of these species has specialty chemical additivesthat address them individually. While there is documen-tation on the benefits of certain types of additives(Gidley, 1971; Hall, 1975), other authors have reporteddamage caused by a similar system in multiphase-flowenvironments (Muecke, 1979; Davies et al., 1988).Shaughnessy and Kline (1983) showed the difficultieswith high bicarbonate ion content in formation waters.The use of HCl was not sufficient to keep the well fromredamaging itself quickly. They used an ingenioustreatment with a form of ethylenediamenetetraaceticacid (EDTA) to both remove the calcium carbonatescale that had damaged productivity and prevent recur-rence of the scale for long periods of time.

High sulfate ion contents (>1000 ppm) exist in someformation waters. Spending HCl on calcium carbonatesgenerates a high concentration of calcium ions that willprecipitate calcium sulfate when the spent acid mixeswith formation water. This can be prevented by pre-flushing the formation water away from the wellbore.In sandstone formations, water containing ammoniumchloride (NH4Cl) should be used as a preflush fluid.

18-7.4. Crude oil compatibilityAnother serious problem with formation fluids is thereaction of crude oil with acid. Removal of the residualhydrocarbon phase improves the effectiveness of aque-ous acid systems. Some oils, particularly black heavyoils (less than 30°API gravity), react with acid to formeither damaging sludge (precipitated asphaltenes) or astable emulsion. Moore et al. (1965) reported this prob-lem and gave the treatment to prevent it. Sometimessludge preventers and emulsion breakers cannot preventthe formation of stable emulsions. Houchin and Hudson(1986) discussed similar problems with organic deposits.Recent work shows how dissolved iron creates morestable sludges and emulsions with these crude oils. Some“difficult” crude oils require a hydrocarbon solvent bufferbetween the crude oil and the acid that is mutually com-patible with both the crude oil and the acid. The bufferreduces contact between the acid and the problem oiland prevents or reduces the problems with sludge andemulsion. Using this technique in one Wyoming oilfield increased the success rate from 25% to 75%.

Asphaltene particles can precipitate during produc-tion as a result of a pressure drop. Solvents can beused to loosen and partially or completely dispersethem. This action helps the acid do a better job ofdissolving acid-soluble solids. When a well has been

completed with oil-base muds, presoaks with an aro-matic solvent and producing back before acidizing arehelpful. Solvent formulations and surfactant solutionsare available as a pretreatment to clean up oil-basemud filtrates and restore the formation to a water-wetcondition.

Gidley (1985) reported that the use of CO2 as a pre-flush to acid treatments has many benefits, includingreducing the volumes of acid required to generate suc-cessful production increases. This type of preflush hasworked well in core studies to enhance crude oil dis-placement and improve mobility.

18-7.5. Formation mineral compatibilitywith fluid systems

An analysis of the formation minerals is important fordesigning the HCl preflush, mud acid treatment andoverflush in sandstone formations. Basic questionsthat must be answered are listed here.

1. How much of the formation will dissolve in HCl?

Where a high HCl solubility exists (20% or more),mud acid should not be used. This statement is basedon the assumption that HCl-soluble compounds arecarbonate-base minerals. These minerals are thecommon cementing material of sandstone forma-tions. Dissolution of this cementing material releasesparticles that can decrease the permeability. In addi-tion, precipitants exist as small discrete particles thatcannot be produced back through the perforationsand out of the well. The use of mud acid in sand-stones with a high carbonate content producesnumerous precipitates.

Calcium carbonate, magnesium carbonate andiron compounds are soluble in HCl. Even feldsparsand chlorite clay are slightly soluble (Gdanski andPeavy, 1986). Recent investigations of HCl involve-ment in the HF reaction with clays show that theHCl is consumed on the clay surfaces, and thisshould also be accounted for in the preflush volumesand in the HCl:HF ratio of the main fluid stage(Gdanski and Peavy, 1986). Zeolite minerals canproduce gelatinous precipitates when exposed toHCl. This can be avoided by the use of organic acidmixtures, as discussed later in this chapter. Sufficientvolumes of HCl must be injected ahead of the mudacid to dissolve enough of the HCl-soluble materialsbefore the mud acid or spent mud acid reaches them.


2. How much of the formation will dissolve in mudacid? Will acid reaction by-products precipitate?

The volume of mud acid used depends on the con-centration of the acid and the amount of damage.Optimizing this volume can be done only by detail-ing the damage in a valid numerical simulator(Perthuis et al., 1989). The HCl:HF ratio and con-centration are selected to prevent or reduce the for-mation of damaging precipitates (Table 18-5).

Some minerals automatically precipitate fluoridecompounds when high concentrations of HF areused, particularly 6% HF. Even 3% HF will precip-itate potassium fluosilicate when mud acid reactswith potassium feldspar. HF-dissolved sodiumfeldspars do not usually precipitate sodium silicatewith 3% or less HF.

When HF is used in a formation containing clay,feldspar and micas, hydrous silica always precipi-tates. Hydrated silica has been reported in a sticky,gelatinous form that if left stagnant can attach tothe mineral surfaces. However, Crowe’s (1986)work on sandstone cores demonstrates that hydratedsilica does not precipitate as a sticky, gelatinousmass. The reaction between the spent mud acid andformation fines is a topochemical reaction, withhydrated silica deposited on the surface of the fines.

It is important to design the overflush to diluteand displace the hydrous silica at least 3 to 5 ftaway from the wellbore to reduce the effect of thedamage. To avoid silica-creating damage, it isimportant to limit any static time while the mud

acid stage is in the near-wellbore area. If the pre-cipitates are diluted and flushed, the likelihood ofpermanent damage is reduced. The by-products canbe flushed away and sometimes even stabilize for-mation fines in the process. If the well is thenreturned to flow quickly, some of the precipitatemay be produced back. “Quickly” refers to non-producing time, not the rate at which flowback isaccomplished. The quick return of fluids can helpimprove cleanup of the formation after acid treat-ment, regardless of the flow rate. If an inadequateamount of HCl preflush is used in formations with5% to 15% carbonate, residual carbonate near thewellbore reacts with spent HF (fluosilicic acid orAlF3), and voluminous precipitates form. Thehydrated precipitates occupy a much larger volumethan that of the original clays and carbonate dis-solved.

3. Will iron be a problem?

Where a lot of iron-rich minerals are in the formation,dissolved iron can precipitate in the formation. It iswell known that ferric iron precipitates as acid spendsto a pH of 2 to 4. The precipitation of iron hydroxide,where concentrations as high as 10,000-ppm iron arepresent in solution, can be prevented by adequatetreatment with a sequestering agent such as nitrilotri-acetic acid (NTA), EDTA, citric acid or combinationsof acetic and citric acid (Shaughnessy and Kunze,1981; McLeod et al., 1983; Paccaloni, 1979a, 1979b)(see Chapter 15). Crude oil with a high asphaltenecontent should be tested for sensitivity to different ironconcentrations. Sludge and ridged-film emulsions arecommon problems for these crude oils.

Damage with iron hydroxides can be compoundedby the high iron concentration that comes off the sur-face of the tubing during acid injection (De Ghetto,1982). Injecting acid through new tubing can behighly damaging in this respect (Fogler and Crain,1980; Lybarger and Gates, 1978a, 1978b). Newlymanufactured tubing has a crust of mill scale, ormagnetite, which is a form of ferric and/or ferrousoxide. The mill scale is dissolved and loosened bythe acidic fluid, and in the early stages, partiallyspent, iron-rich weak acid is injected. Particles ofmill scale can then be injected into the perforationsand trapped there. Injected acid will continue to dis-solve the mill scale, creating ferric chloride thatenters the formation. If the ferric chloride combineswith iron leached out of iron-rich chlorite clay or


Table 18-5. Acid use guidelines for sandstone acidizing (McLeod, 1984).

Condition or Mineralogy Acid Strength (blend)

HCl solubility > 20% HCl only

High permeability (>50 md)

High quartz (>80%), low clay (<5%) 12% HCl–3% HF†

High feldspar (>20%) 13.5% HCl–1.5% HF†

High clay (>10%) 10% HCl–1% HF‡

High iron/chlorite clay (>15%) 10% acetic acid–1% HF§

Low permeability (≤10 md)

Clay (<10%) 6% HCl–1% HF

Clay (>10%) 6% HCl–0.5% HF

† Preflush with 15% HCl‡ Preflush with 10% HCl§ Preflush with 10% acetic acid

other iron compounds, a large amount of iron hydroxide precipitates is possible, which can severelydamage the formation. This aggravated iron damagecan be prevented by pickling (cleaning) new tubingto remove mill scale and then circulating the pick-ling acid back out of the well, as discussed later.

4. Do the sidewall core samples contain drilling mud-cake?

Testing results from samples of sidewall cores withexcessive mudcake should be reviewed closely andcompared to the log response and other datasources such as a produced water sample analysis.High concentrations of drilling mud solids (e.g.,barite, smectite, mica, bentonite or illite minerals)should not be present in clean, high-porosity sand-stone formations. The solubility of the samples inmud acid mixtures may be exaggerated.

18-7.6. Acid type and concentration Permeability and mineralogy determine the compati-ble concentration of HCl or acetic acid in the preflushstage and HF and HCl in the mud acid stage. Con-centration recommendations are provided in Table 18-6 for preflush fluids and Table 18-7 for mud acidfluids. The previously presented acid use guidelines inTable 18-5 were published in 1984 (McLeod, 1984).Lower mud acid concentrations were first recom-mended in 1970 by Farley et al. (1970) to preventunconsolidation in California sandstones. U.S. WestCoast sandstones are generally rich in potassium feld-spars. Holcomb (1975) published work on the firstsuccessful acid stimulation of the Morrow formationin West Texas–New Mexico with weak acid (6% HCl–1.0% HF and 3% HCl–0.5% HF). Lybarger and Gates(1978b) subsequently developed the slow-rate, low-


Table 18-6. Fluid selection guidelines for preflush fluids.

Mineralogy Permeability

>100 md 20 to 100 md <20 md

<10% silt and <10% clay 15% HCl 10% HCl 7.5% HCl

>10% silt and >10% clay 10% HCl 7.5% HCl 5% HCl

>10% silt and <10% clay 10% HCl 7.5% HCl 5% HCl

<10% silt and >10% clay 10% HCl 7.5% HCl 5% HCl

Note: Selection guidelines for all temperatures

For 4% to 6% chlorite/glauconite, use <20-md guidelines with 5% acetic acid.For >6% to 8% chlorite/glauconite, do not use HCl; use 10% acetic acid preflush to mud acid plus 5% acetic acid.For >8% chlorite/glauconite, do not use HCl; use 10% acetic acid and organic mud acid.

For <2% zeolite, use 5% acetic acid in all fluids containing HCl and preflush with 10% acetic acid.For >2% to 5% zeolite, do not use HCl preflush; use 10% acetic acid preflush and overflush to mud acid containing 10% acetic acid.For >5% zeolite, do not use HCl in any system; use 10% acetic acid preflush and overflush to organic acid prepared from 10% citric acid/HF.

Table 18-7. Fluid selection guidelines for mud acid fluids.

Mineralogy Permeability

>100 md 20 to 100 md <20 md

<10% silt and <10% clay 12% HCl–3% HF 8% HCl–2% HF 6% HCl–1.5% HF

>10% silt and >10% clay 13.5% HCl–1.5% HF 9% HCl–1% HF 4.5% HCl–0.5% HF

>10% silt and <10% clay 12% HCl–2% HF 9% HCl–1.5% HF 6% HCl–1% HF

<10% silt and >10% clay 12% HCl–2% HF 9% HCl–1.5% HF 6% HCl–1% HF

Notes: Selection guidelines for all temperatures

For 4% to 6% chlorite/glauconite, use <20-md guidelines with 5% acetic acid.For >6% to 8% chlorite/glauconite, use 10% acetic acid preflush to mud acid plus 5% acetic acid.For >8% chlorite/glauconite, use 10% acetic acid and organic mud acid.

For <2% zeolite, use 5% acetic acid in all fluids containing HCl.For >2% to 5% zeolite, use 10% acetic acid preflush and overflush to mud acid containing 10% acetic acid.For >5% zeolite, use 10% acetic acid preflush and overflush to 10% citric acid/HF.

pressure injection technique, in which they used 7.5% HCl–1.5% HF for Gulf Coast sandstones.

The guidelines are based on industry practices andthe chemistry of sandstone acidizing from limitedresearch studies; however, many case histories havecorroborated them with high levels of success.

From 1975 through 1980, poor success in acidizingseveral formations such as the Frio and Wilcox inTexas led to the concern that spent acid generateddamaging precipitates. Quick, qualitative laboratorybench tests confirmed that precipitates occur depend-ing on the solubility of the acid reaction products.These same observations were first pointed out bySmith and Hendrickson (1965), in particular the prob-lem with sodium fluosilicate. Labrid (1971) discussedthe precipitation of hydrous silica, which caused someplugging in cores. This damage was later demonstrat-ed by Shaughnessy and Kunze (1981) by leavingspent acid in the core for several hours, a conditionthat occurs in an actual acid job. This allows the slowreaction rate between the spent mud acid and the clayminerals and feldspars (aluminosilicates) to producehydrous silica that decreases the permeability.

Crowe (1986) showed that there was little or noplugging during the injection of spent acid (fluosilicicacid) in a Berea core. This reassuring result matchesthe behavior seen during acid injection; however,plugging conditions are worse during the static condi-tions of shut-in examined by Shaughnessy and Kunze(1981). Crowe’s work does not address shut-in condi-tions or conditions of inadequate preflush with HCl.Walsh et al. (1982) presented theoretical work on theequilibrium of spent acid and showed that pluggingprecipitates are possible with various acid concentra-tions and mineral compositions in sandstones.

Research by Bertaux (1986) addresses reprecipitationand plugging problems in acidizing sandstones contain-ing potassium feldspars. The solubility of potassiumfluosilicate is less than one-half of the solubility of sodi-um fluosilicate, which is why lower mud acid concen-trations are recommended in the presence of potassicfeldspars such as orthoclase or microcline (KAlSi3O8).The amount of potassium in the mineral orthoclase(potassium feldspar) is enough that the solubility ofpotassium fluosilicate is exceeded at normal reservoirtemperatures (less than 200°F) by dissolving pureorthoclase in regular mud acid (12% HCl–3% HF).Bryant and Buller (1990) observed the generation offines by the reaction of HCl with feldspars.

The early work of Smith et al. (1965) in acidizingvarious cores with different permeabilities shows differ-ent responses to mud acid. C. F. Smith (pers. comm.,1979) found it more difficult to stimulate wells produc-ing from sandstones with permeabilities of 10 to 60 md,which are much lower than the usual Berea sandstonepermeability (100 to 300 md) in mud acid experiments.Smith attributed much of the difficulty to the release offines by the acid.

Long-core tests performed by R. D. Gdanski (pers.comm., 1985) in low-permeability sandstone at hightemperatures demonstrate increased permeability withmud acid in the first two 4-in. cores in series anddecreased permeability in the third 4-in. core in a totalcore length of 16 in. Gdanski and Peavy (1986) alsodiscussed the depletion of the preflush HCl in sand-stone acidizing by ion exchange of H+ with K+ or Na+

ions on the formation clay minerals. This gives newinsights into potential problems with sandstones rich in clay minerals with high CECs (smectite and illite).

Simon et al. (1979) showed that HCl attacks chlo-rite clay, extracting the iron and magnesium and leav-ing an amorphous aluminosilicate residue. J. M.Kullman (pers. comm., 1988) observed pluggingproblems with these residues as well as with rim coat-ings of chlorite liberated by HCl in core flow tests.Chlorite is prevalent in the Morrow formation in thesame areas where Holcomb (1975) worked and couldbe the reason why weaker acids worked better in thatenvironment (i.e., they were easier on the chlorite).Thus, weaker acids are recommended for use in sand-stones with significant chlorite content and acetic acidis recommended to dissolve the carbonate and notattack chlorite ahead of the mud acid.

A common misunderstanding about the recom-mended acid concentrations is that they are notabsolute. The guidelines are a conservative approachto avoid problems with spent acid precipitates whenno previous experience exists in acidizing a particularformation. Significant deviation from these guidelinesshould not be necessary. Unless evaluated experienceexists, the guidelines are the most reliable source ofinformation. Also, acid flow tests with cores are reli-able if long cores are used and if the spent acid is leftin a portion of the unacidized core for the same periodof time and at the same temperature that will occur inthe downhole treatment. These tests are expensive andtherefore seldom performed.


18-8. Methods of controlling precipitates

The methods used to control the precipitates causedby acidizing are proper acid staging, lower acid con-centrations, correct usage of preflushes and sufficientoverflushing, as illustrated in the following guidelines.

18-8.1. PreflushPreflush with

1. 5% to 15% HCl

2. acetic acid (see Section 18-3).

The preflush displaces formation brine away fromthe wellbore to prevent it from mixing with reactedmud acid and causing a damaging precipitate. If theformation contains more than 1% to 2% carbonate, an HCl preflush is necessary to dissolve the carbonate,prevent the waste of mud acid and prevent formationof the insoluble precipitate CaF2.

If completion brines such as seawater, potassiumchloride (KCl), calcium chloride (CaCl2) or calciumbromide (CaBr) have been used in the well prior toacidizing, the brines will mix with the mud acid in theformation. Preflushing the mud acid with HCl or brinecontaining ammonium chloride to dilute the brinesand remove them away from the wellbore helps avoidthis problem.

Preflushes can also be used to displace and isolateincompatible formation fluids (either brine or crudeoil), as previously discussed.

18-8.2. Mud acid volume and concentration• Volume

Gidley (1985) reported that for the most successfulmud acid treatment, more than 125 gal/ft of mud acidis required. Less may be used where only shallowdamage exists around new perforations (e.g., 25 to 75 gal/ft is used to remove mud damage or in a spear-head treatment as an aid to perforation breakdownprior to hydraulic fracturing).

When the damage is quantified, a simulator canbe used to optimize the volumes of mud acid mix-tures to be used. Simulators can be used to aid themodification of volumes if several job stages areused (see Chapter 14).

• Concentration

Regular mud acid (12% HCl–3% HF) is the normalconcentration to use to remove damage in cleanquartzose sands. Field experience has shown thatweaker concentrations (0.5% to 1.5% HF) can beeffective for other sands. Mineral composition froma laboratory analysis can also dictate when lessthan 3% HF should be used. If the combined per-centage of clay and feldspar is more than 30%,1.5% HF or less should be used. Field experiencewith some tight sandstones has shown that concen-trations as low as 0.6% HF may be used (e.g., theMorrow formation in Texas and New Mexico;Holcomb, 1975). If the appropriate concentration is in doubt, an acid response test on a typical coreshould be performed if a core sample is available.

18-8.3. Postflush or overflushThe overflush is an important part of a successful sand-stone acidizing treatment. An overflush has severalpurposes:

• to displace nonreacted mud acid into the formation

• to displace mud acid reaction products away fromthe wellbore

• to remove oil-wet relative permeability problemscaused by some corrosion inhibitors.

When overflushing the acid treatment, it is impor-tant to remember that miscible fluids are required toperform these listed functions. Aqueous-base liquidsshould therefore be considered as the first displacingand flushing fluid. Another fluid system can then beused for addressing the other concerns as the condi-tions dictate. This suggests that multiple fluid typesshould be used as overflush stages for a given set ofcircumstances.

Typical overflushes for mud acid treatments are

• water containing 3% to 8% ammonium chloride

• weak acid (3% to 10% HCl)

• diesel oil (oil wells only and only following a wateror weak acid overflush)

• nitrogen (gas wells only and only following a wateror weak acid overflush).

Studies of displacement fronts indicate that thereactivity and fluid character of the overflush have amajor influence on the volume required to displace the


spent mud acid. For most overflush fluids (weak HCland water containing ammonium chloride), volumesless than twice the mud acid stage should be consid-ered inappropriate. The volume of overflush shouldnever provide less than 3 ft of radial penetration. Thismeans that for most situations, the overflush should beat least 200 gal/ft of perforations to push all the spentacid past the critical flow radius of 3 to 5 ft. A largeoverflush is necessary to prevent the near-wellboreprecipitation of amorphous silica, which occurs afterspent HF contacts the clay in the formation. At forma-tion temperatures of 200°F or higher, amorphous sil-ica precipitation occurs while the mud acid is beingpumped into the formation. The precipitate is some-what mobile at first but may set up as a gel after flowstops. If it is kept moving by overflushing with watercontaining ammonium chloride or weak acid, it isdiluted and dispersed far enough away from the well-bore to where it has a less harmful influence.

Recent experience indicates the advantage of includ-ing HCl or acetic acid in the first part of the overflushto maintain a low-pH environment for the displacedspent mud acid stage. This supports the original recom-mendations of Smith and Hendrickson (1965). As thehydrogen ions adsorb on nonreacted clay deeper in theformation, the pH rises unless it is replaced by freshacid in the first part of the overflush. Although the mosteconomic overflush of a mud acid treatment is watercontaining 3% to 8% ammonium chloride with 10%ethylene glycol monobutyl ether (EGMBE) and apolyquarternary amine clay stabilizer, it does notaddress the pH problem without acetic acid addition.Also, certain chemicals can be added to acids to pre-vent or reduce the precipitation of some compounds(e.g., iron complexing agents, sulfate scale inhibitorsand antisludge agents).

An example of the role of reservoir mineralogy waspresented by Boyer and Wu (1983) in evaluating acidtreatments in the Kuparuk River formation in Alaska.Their results indicate that fluoboric acid significantlyreduces the amount of hydrated silica formed in com-parison with conventional HCl-HF systems.

18-9. Acid treatment design considerations

Once a well is determined to be a candidate for amatrix acid treatment, the design should account formany different issues. A systematic approach to the

estimation and calculation of critical parameters isrequired. Pressures, rates and volumes must conformto the constraints of the mechanical conditions of thewell equipment and the available space for surfaceand pumping equipment, along with logistical timeconstraints. The following discussion includes the dif-ferent types of acid sequences, how and why attemptsare made to retard the acid reaction rate, potential con-tamination from various sources and the resultantdamaging precipitation. The basic quality assuranceand quality control (QA/QC) checks and the design of treatments from both a formation compatibility andoperational standpoint are included.

An acid design technique based on the work ofWilliams et al. (1979) for mud acid injection is in theSPE Monograph Acidizing Fundamentals. Althoughthe technique is based on studies of one sandstone, itdoes show the important effects of temperature andinjection rate on live mud acid penetration. Well illus-trated is the small depth of invasion of mud acid insandstone, particularly when formation temperaturesare greater than 200°F. Live mud acid usually pene-trates only about 6 to 12 in. into the sandstone beforespending. This work was extended by Hill et al. (1977),who incorporated the effect of specific mineralogy andadded the reaction kinetics of HF to the slower butfinite quartz reaction rate. They also discussed the dif-ferent reactivities of clay minerals and the importanceof their morphology in the pore network. McElhiney et al. (1979) also reviewed the progress in methods ofpredicting live mud acid penetration and permeabilityincreases in sandstone. These are worthwhile develop-ments, but a simple guideline of wellbore contact timeoffers a practical solution to determining acid volumesto remove near-wellbore damage.

18-9.1. Selection of fluid sequence stagesThe damage type dictates the sequence of acid sys-tems used for each treatment. The preflushes, mainstage and overflush should be matched to the type ofdamage. Diversion should be matched to formationcharacteristics and the type of treating fluid. Diversionguidelines are provided in Chapter 19. Each type ofdiversion technique is addressed as it pertains to sand-stone treatments in this section. The sequence of fluidsthat compose an acid treatment can be the key to mak-ing a treatment successful.


18-9.2. Typical sandstone acid job stagesA preflush stage should be used ahead of the HClespecially when high sulfate ion or high bicarbonateion concentrations exist in the formation connatewater or seawater or when CaCl2, KCl or CaBr com-pletion fluids have been used and calcium carbonate is a formation mineral. HCl dissolution of the calcitegenerates high calcium ion concentrations that mixwith the incompatible formation water and generatescale (calcium sulfate or calcium carbonate).

18-9.3. Tubing pickleOne of the first items to be addressed when matrixtreatments are considered should always be a tubingpickle (cleaning). This one step can have a significantimpact on the success of treatments. Tubulars, regard-less of how new, have scale, rust and other debris thatresult from handling, installation and production andthat can be loosened by the solvents and acid injectedinto the well. The pickling process may be multiplestaged and may involve expensive solvent packages.Typically, a small treatment containing solvent andacid stages will greatly improve, if not completelyeliminate, the problems associated with tubular debris.The pickling process should be included in the proce-dure and time allotted for job execution. The purposeof the pickling process is to

• remove rust, iron oxides and scale

• dissolve oily films and pipe dope that could plugthe downhole equipment and perforations

• limit the amount of iron that gets into the formationand contacts the crude oil.

18-9.4. PreflushesThe sequence of fluids in sandstone treatments isdependent largely on the damage type or types. The useof multiple-stage preflushes should functionally addressthe different types of damage and thereby prepare thesurfaces for the main treatment fluids. Hydrocarbon sol-vents are used to remove oil films and paraffin depositsso the aqueous acid systems can contact the mineralsurfaces. These types of preflushes affect treatment suc-cess and should not be overlooked or demoted inimportance. Acid-compatible brines (e.g., brine contain-ing ammonium chloride) can be used as an excellent

preparatory flush to help remove and dilute acid-incom-patible species (e.g., potassium or calcium). An exam-ple of a preflush sequence is preceding the HCl portionof the preflush with a large quantity of brine containingammonium chloride followed by a hydrocarbon-basesurfactant mixture. The purpose of the brine preflush isto dilute the incompatible species to soluble levels. Thehydrocarbon mixture has the same purpose as men-tioned previously.

The next consideration for preflushes is compatibil-ity with formation fluids. Certain crude oils have ahigh sensitivity to acidic mixtures. These situationsmay require dilution with hydrocarbons or other iso-lating or buffering fluid systems (e.g., foams). Furthercompatibility consideration should be given to theiron content of the initial injection fluids that contactthe crude or condensate, because even low iron con-centrations can cause sludge formation. Displacementof the fluids away from the near-wellbore regionreduces the potential of problems that can reduce pro-duction success and limit or halt the injection process.

HCl preflushes in sandstone acidizing are extremelyimportant. Their function is to remove as much of thecalcareous material as possible prior to injection of themud acid. Strength and volume guidelines are basedon the criteria set in work by Labrid (1971), Fogler etal. (1976), Kline (1980), Kline and Fogler (1981) andWalsh et al. (1982). Their theoretical work was furtherinvestigated and confirmed by field work by Gidley(1985), McLeod (1984), Thomas and Crowe (1981)and others. Table 18-6 provides selection guidelinesfor the appropriate strength of the HCl preflush. Thetable is based on the solubility of the formation in HCland the requirement of minimizing the remaining car-bonate or calcite prior to introducing the mud acid.

Figure 18-5 summarizes Walsh et al.’s (1982) workon the selection of HCl-HF formulations based on theamount of calcite remaining after the preflush. Thefigure illustrates the importance of HCl preflushes.The HCl preflush step should never be neglectedwhen using mud acid mixtures. A few systems con-taining HF can be injected without an HCl preflush,but these are systems with extremely low HF concen-trations, such as fluoboric acid. These systems can beused without an HCl preflush because the HF concen-tration in fluoboric acid is low enough not to present aprecipitation potential.


18-9.5. Main fluid stageThe HCl-HF mixture used in each treatment shouldconform to the guidelines in Table 18-7. Work byWalsh et al. (1982) demonstrates that low HF concen-trations should be used to avoid the precipitation ofAlF3 or CaF2 if the remaining calcite cannot be quanti-fied. Their work also suggests that 12% HCl–3% HFcan be used even in low-calcite environments withouta precipitation problem. Some significant problemsthat may occur in high-clay-content formationsinclude compromised formation integrity and exces-sive fines generation. These conditions can be theresult of too high HF concentrations. The volumesshould be determined using a field-validated simulatorto sensitize the severity of the damage. Gidley (1985)reported that the percentage of acidizing successesincreases as the volume of mud acid increases for gaswells, whereas a maximum of 100 to 125 gal/ft of per-forations is required to maximize success for oil wells.This study did not take into account the preflush usedor the quantity of overflush. If diversion is maximizedand the damage is known or perceived to be shallow,then smaller quantities per foot can be used. The acidstrength is important, because precipitation potentialand formation matrix collapse are problems that canbe irreversible. Table 18-5 provides the original guide-lines for HCl-HF mixtures to obtain the appropriateHCl:HF ratio to avoid precipitation and formation col-

lapse. Table 18-7 is derived from this guideline on thebasis of further laboratory testing and extensive fieldexperience.

18-9.6. Overflush stageThe purpose of the overflush is twofold. First, it shoulddisplace the main fluid stage more than 3 to 4 ft awayfrom the wellbore, which is the critical matrix area forradial flow. Second, the portion of the main stage that is not displaced should be diluted. Both of these factorshelp to eliminate damage in the near-wellbore areacaused by the precipitation potential of the spent mainfluid stage. Overflush fluids must be chosen carefully toavoid creating damage during the treatment flowback.

Overflush systems should meet the following crite-ria. The portion of the overflush immediately follow-ing the main fluid stage should be aqueous based,have a low pH value and have dilution potential forthe spent mud acid. Smith et al. (1965) recommendedan HCl overflush to maintain a low-pH environmentand match the fluid density of the previous stages. Theremainder of the overflush should be miscible andcompatible with the previous stages. The total mini-mum overflush volume must completely displace themain fluid stage at least 4 ft away from the wellbore.Any anisotropy of the formation permeability canwarrant doubling or tripling the overflush volume


Figure 18-5. HCl-HF treatment fluid selection based on AlF3 or CaF2 precipitation (Walsh et al., 1982).

Max

imum

wei

ght %

of H

F

in a

cid

form

ulat

ion

0 10 20 30 40

16

14

12

10

8

6

4

2

0

Weight % of HCI in acid formulation

0% calcite

Ideal case

3% calcite

6% calcite

if the energy in the reservoir is sufficient to unload theinjected fluid. Although not previously reported, oneof the authors of this chapter has achieved notableimprovement where larger overflushes were used.This is especially true for wells where heavy bromidebrines are used during the completion phase.

18-9.7. Diversion techniquesCommon practice in sandstone acidizing is for thediverter stage to be applied as merely another stage.This is an excellent way to ensure that the main fluidstages are properly isolated by the preflush and over-flush fluids. Some methods described in other chapters(e.g., ball sealers, rock salt) are not suitable for use insandstone acidizing. The compatibility of the divertingagent with the live and spent acid species requiresknowledge of the chemicals. Some forms of benzoicacid solids should not be used because the sodiumcontent in some environments causes precipitation.Rock salt should never, under any circumstances, beused as a diverter with HF mixtures. Other materialscan be incompatible with the solvents and surfactantsused in the acid systems.

Operational considerations should always be takeninto account when designing diversion stage sequences.The use of oil-soluble resins (OSRs) dictates that themethod should be slug application. The last stage ofpreflush can contain a solvent to help dissolve the OSRmaterial, creating uniform injectivity of the last sequencethroughout the interval. A few exceptions apply to usingcertain acid systems. For example, when using fluo-boric acid as the overflush to a mud acid treatment forsilt and clay control, the fluids should be staged as inTable 18-8.

Other sequences could include brine flushes sepa-rating the hydrocarbon preflush from the HCl preflushbefore the main fluid stage; brine or weaker acidstages could be used to increase the volume of theoverflush stage.

18-9.8. Typical sandstone acid job stagesThe key to successful staging is to address all damagetypes present and maintain compatibility with forma-tion fluids and formation mineralogy while minimizingthe quantities of fluids injected. Table 18-9 provides alisting of typical stage sequences for a sandstone acidiz-ing treatment.


Table 18-8. Acid treatment sequence and fluid options.

Stage Fluid System

1. Preflush Brine

Hydrocarbons

HCl

2. Main fluid HCl-HF formulation

3. Overflush HCl or NH4Cl

4. Diverter Foam or slug OSR

5. Repeat stages 1–4 as necessary with 1–3 as the last fluid sequence

6. Fluoboric acid With diverter solvent for OSR or foam-weakening agent (mutual solvent)

7. Fluoboric acid diverter Fluoboric acid–based fluid system, either foamed or slug OSR

8. Fluoboric acid Fluid left at the perforations

18-10. Matrix acidizing design guidelines

Matrix acidizing is the process of injecting acid intothe formation in radial flow below fracturing pressureto remove damage and restore the permeability to theoriginal reservoir permeability or higher. Moredetailed procedures are available from McLeod et al. (1983), who recommended the following steps fortreatment design:

1. Estimate safe injection pressures:

a. determine present fracturing gradient

b. determine present bottomhole fracturing pressure

c. determine allowable safe injection pressure atboth the wellbore and at the surface.

2. Estimate safe injection rate into the damage-freeformation.

3. Estimate safe injection rate into the damaged formation.

4. Select stages required for fluid compatibility.


Table 18-9. Typical stage sequence for a sandstone acidizing treatment.

Stage Stage Reason for Stage Information Stage Stage VolumeNumber Source Composition

1 Crude oil displacement To prevent oil sludge Acid–crude oil Aromatic solvent To achieve 3-ft radialformation by the acid sludge test displacement

2 Formation water To prevent scale HCO3 and SO4 Ammonium chloride To achieve 3-ft radialdisplacement deposition contents from (NH4Cl) at 3%–8% displacement

formation water depending on theanalysis salinity of the for-

mation water

3 Acetic acid Iron compounds in X-ray-diffraction 3%–10% acetic acid CaCO3 (%) Volume (gal/ft)formation (pyrite, siderite, (XRD) analysis 0–5 25hematite), chlorite, clay, 5–10 50zeolites 10–15 75

15–20 100

4 Hydrochloric acid CaCO3 or other HCl- HCl solubility According to core Calculated on the basis of soluble minerals test and/or XRD mineralogy: 3%–15% HCl solubility and porosity

analysis HCl (see Table 18-5) or this schedule:

HCl Solubility Stageof HF (%) Volume

(gal/ft)

<5 505–10 10010–20 200

5 Hydrofluoric acid To remove clay, other XRD analysis, According to formation 75–100 gal/ft(not used for carbon- formation fines and SEM analysis, mineralogy:ates and sandstones mud damage HCl:HF 3%–13.5% HCl where HCl solubility solubilities with 0.5%–3% HF> 20%)

6 Overflush To spend acid and flush Always used 3%–8% NH4Cl or One to two volumes of spent acid away from 3%–5% HCl in all the HCl:HF volume or to the near-wellbore area wells followed by achieve 5-ft radial

nitrogen (gas wells), displacementkerosene (oil wells) or 5% HCl (water injection wells)

7 Diversion To improve injection Used as OSR for oil or low gas/throughout the interval required for oil ratio wells, foam for

heterogeneous either oil or gas wellsformation and water-soluble resinspermeability for water injector wells

5. Calculate volume of each stage required:

a. crude oil displacement

b. formation brine displacement

c. HCl stage or acetic acid stage

d. mud acid stage

e. overflush stage.

6. Select acid concentrations according to formationmineralogy.

18-10.1. Calculations• Fracturing pressure

Matrix treatments are defined as fluid injectionoccurring below fracturing pressure. If the fluidis injected above fracturing pressure, the acid maybypass the damage. It is important to perform somebasic calculations to ensure that this pressure is notexceeded, and the exercise also provides the pres-sure and rates that may occur. Thorough discussionsof fracturing pressure and bottomhole injectionpressure and how these aspects are derived areprovided in Chapters 3 and 20, respectively.

An important item to keep in mind with matrixtreatments is that fracturing pressure is related tothe pore pressure but is not directly proportional.As the pore pressure declines, so does the fractur-ing pressure. Although this is not a one-to-onerelationship, it can be important when treating low-bottomhole-pressure wells. The hydrostaticpressure exerted by the column of fluid in the tubu-lars can be sufficient to fracture the formation.

• Injection rates

The injection rate can be as significant as the injec-tion pressure. The maximum injection rate thatdoes not fracture the formation can be estimated by

(18-5)

where qi,max is the injection rate in bbl/min, k is theeffective permeability of the undamaged formationin md, h is the net thickness in ft, gf is the fracturegradient in psi/ft, H is the depth in ft, ∆psafe is thesafety margin for the pressure in psi (usually 200 to 500 psi), p is the reservoir pressure in psi, µ is theviscosity of the injected fluid in cp, re is the drainage

radius in ft, rw is the wellbore radius in ft, and s isthe skin effect factor. B is the formation volume fac-tor and has a value of 1 for noncompressible fluids.

Equation 18-5 is a simple way of estimating theinjection rate. However, Eq. 18-5 does not accountfor several factors, which are detailed in Chapter 20for accurately modeling the injection rate. Equation18-5 with zero skin effect and with the estimatedvalue of the skin effect provides respective valuesfor the minimum and a maximum pump rate duringthe job. These values enable allocating appropriateequipment for the treatment. True transient injectionmonitoring can be done in real time on location tomonitor the progress of the job.

• Friction pressure estimation

Accurate fluid friction pressure is a difficult parame-ter to obtain. Because the tubular arrangement canbe different in each case, a fairly accurate number isimportant. The following limited-range equation hasbeen used with relatively good accuracy for estimat-ing friction pressures for Newtonian fluids at ratesless than 9 bbl/min:

(18-6)

where ppipe friction is the friction pressure in psi/1000 ft,ρ is the density of the fluid (specific gravity) in g/cm3,q is the pump rate in bbl/min, and D is the diameter ofthe pipe in in. Coiled tubing friction pressures can alsobe calculated using Eq. 18-6.

• Fluid volumes

If it is assumed that acid flows through porousmedia with a front that is uniform and stable, thenthe injection is piston-like and the first fluid inshould be the last fluid out. To calculate fluid vol-ume, the following equation should be sufficient:

(18-7)

where Vp is the pore volume for the distance s ingal/ft, φ is the fractional porosity, and rs is the dis-tance it is necessary to penetrate the damaged ordisplaced section in ft.

Mud acid treatments do not dissolve much of theformation minerals but rather dissolve the materialsclogging the pore throats. This means that significantchanges in the flow distribution of the injected fluidsoccur during the treatment as the pore-pluggingmaterials are dissolved (see Chapter 19 on diver-


qkh g H p p

Br

rs

i,max

f safe

e

w

=× ×( ) − −[ ]

+

−4 917 10 6.,

∆

µ ln

V r rp s w= −( )[ ]7 48 2 2. ,φ π

pq

Dpipe friction = 518 0 79 1 79 0 207

4 79

ρ µ. . .

.,

sion). Because the acid does not follow the idealmode, adjustments to the injection volumes must bemade. Significant changes in the fluid can also occurin the tubulars, before the fluid reaches the forma-tion. The dilution of stage composition and spendingare just some of the complications that must be addressed by the designer. The use of smaller tubu-lars, such as coiled tubing, during acid treatments cancontribute to a better acid job by facilitating the main-tenance of stage integrity and reducing displacementvolumes. Mechanical limitations associated with arti-ficial lift (e.g., gas lift) are more easily overcome bythe use of coiled tubing. The risks of leaking valves,undiluted acid remaining in the mandrels and acidleaking into the tubing/casing annulus are avoided.The limited injection rate coincidentally controls thecontact time. The pump rate and extraction out ofthe tanks holding the acid can create a bottleneckduring execution. A complete understanding of theoperational aspects is necessary for proper execution.

One of the considerations in selecting the stagevolumes is the tubulars. The volumes of diverter andtheir location in the tubulars while injecting must beconsidered, especially for the use of foam diverters.When using foam diversion techniques, brief shut-downs or momentum changes are called for to maxi-mize diversion. If the foam is in the tubulars whenthe shutdown occurs, phase separation of the foamcan occur, affecting the foam diverter performance.

Another consideration is the preflush activity. If formations do not have much solubility in HCl,operators have tended to lower the volume of acidpreflush and use brine. However, Gdanski andPeavy (1986) reported that this is not a good ideabecause the HCl preflush performs the vital func-tion of cation exchange, which prepares the mineralsurfaces for the HF mixture. The cation exchangemust otherwise be done by the HCl portion of theHF mixture, which raises the pH of the acid systemand induces the precipitation of silicate complexes.As a minimum, the preflush should penetrate thesame distance as the HF mixture (e.g., if the HFblend volume penetrates 2 ft, then the preflushshould penetrate a minimum of 2 ft).

Where the HCl solubility is moderate to high,more HCl is necessary. The following equation isused to calculate this volume and address the HCl-soluble materials:

(18-8)

whereVHCl is the volume of HCl required in gal/ft, XHCl isthe fraction of the bulk rock dissolved by HCl, andβ is the dissolving coefficient expressed as theamount of rock dissolved per gallon of acid and isrelated to the acid strength.

18-10.2. Flowback and cleanup techniquesSelection of the correct flowback procedure is critical.The flowback during multiphase transition periods cancause irreversible damage. The fines loosened duringthe acid job are invariably produced back into thenear-wellbore area. These fines can be removed indiluted concentrations that pass through the comple-tion if small, gradual pressure drops are created. Thiswas demonstrated by Krueger (1986).

The following are key factors to consider for flow-back in sandstone formations:

• The fluids flowing back are more viscous thanthose injected. They are capable of carrying naturalformation fines and other partially dissolved solidsat lower velocities, which can cause pluggingbefore the well cleans up completely.

• The spent acid usually has a higher density than theformation water. The tubing pressure should belower than when connate water is produced, owingto the higher hydrostatic pressure of the spent acid.

• Spent acid has an equilibrium established of poten-tial precipitants, held in place by dissolved gases anddissolved salts. Should these gases (e.g., CO2) beremoved from the spent fluid as a result of creatingan excessive pressure drop, precipitation will occur.

• A minimum velocity is necessary for liquid to bevoided from the tubing without slippage occurring.The minimum velocity to the unload tubing can becalculated. The flow rate and tubing pressure in thiscalculation should include the heavier liquid den-sity. The flow rate should be achieved gradually butsufficiently soon to avoid precipitation in the for-mation. The rate should then be maintained until allinjected fluids are returned and both the tubingpressure and production rate are steady. Plotting thegradual incremental choke changes as pressure andrate stabilize provides insight to the affect of theacid treatments on the formation and completion.


VX r r

HCl

HCl s w=−( ) −[ ]

7 481 2 2

. ,π φ

β

• HF systems should be flowed back immediatelyafter injection of the overflush. The potential dam-aging precipitates that are generated form when thepH increases as the HCl is spent. If the acid isreturned quickly, then the pH change may not reachthe range for precipitation. Many iron precipitatesalso drop out when the pH increases. The exceptionis fluoboric acid treatments. The shut-in timerequired for complete HF generation and fines sta-bilization varies on the basis of temperature.

• The majority of the additives that are injected areproduced back. Because the acidizing additives areby design water soluble, they are partitioned into thewater phase. This can cause separation and floatationequipment problems. The return fluids are also acidic,which creates problems for chemical-electric detec-tion devices in the separation equipment. Local envi-ronmental regulations may dictate water qualitystandards that are difficult to achieve, and disposal of the returned fluids can be cost prohibitive.Alternatives to disposal of the returns as hazardouswaste have been developed, including filtrationthrough inexpensive media (Hebert et al., 1996).

18-11. Acid treatment evaluationMatrix treatment evaluation is the subject of Chapter20. The following is a partial list of the basic ques-tions that should be answered during the evaluation ofan acid treatment to help determine the success or fail-ure of the treatment.

• Was the well damaged? Was there an improvementin the injectivity or transient skin during the treat-ment? Is there evidence that the well was dam-aged?

• Which fluid system or stage accomplished the mostdamage removal? Injectivity values or transientskin values for each of the fluid stages must beevaluated to help identify what damage was caus-ing the most significant production impairment.

• Were emulsions observed during cleanup? Duringthe cleanup of the treatment is when the effective-ness of additives and treatment fluid packagesdemonstrates value. Cleanup time, emulsion prob-lems and facility upset have an economic impactand can be cause for considering different methodsof handling the problems.

• Did any of the treatment fluids or stages create prob-lems during the execution? During the treatmentwere there mixing or handling problems associatedwith any of the additives or the fluid system?

• What are the properties of the formation fluids (i.e.,hydrocarbons and brine) and are these compatiblewith the treating fluids? Post-treatment flowbackinspection and analysis of fluids identifies emul-sions (treating fluid additive formulation), soliddebris (proper acid strength) and other telltale signsof precipitation caused by incompatibilities.

• What is the type of completion injected into andwas this a consideration during the treatment?When injecting into gravel packs or frac and packcompletions, injection rates should be limited if the injected height is limited. Too high an injectionrate through the perforations can evacuate them ofgravel and create an unstable and unsatisfactoryenvironment where the potential exists for forma-tion sand production. This is especially true forhigh-solubility zones where a small percentage of the perforations is taking fluid.

• Was the proper diversion technique or sequencechosen and applied? Most acid treatments requirediversion. The application of proper diversion tech-niques with the selected acid system is vital to theultimate success of the treatment.

• Was the well appropriately prepared before acidiz-ing? When key steps of preparing the wellbore forthe acidizing process are left out (e.g., not picklingthe tubing, not removing the gas lift valves, notremoving the rods or an electrical submersiblepump), the prospects for ultimate success arereduced. Wellbore preparation is especially criticalfor acid treatments. Injection of tubular debris intothe formation can be disastrous, and acid in theannulus of a gas lift completion string is corrosive.

• Were the injected fluids checked using quality con-trol steps? Acid strength and certain additives mustmeet at least threshold ranges for activity and com-patibility limits.

• Was the tubing acid cleaned (pickled)? Rust andmill scale must be removed, even with new pipe.

• Were the pumped fluids sampled and checked forcleanliness and concentration? Although samplesare routinely taken and checked before the jobstarts, samples should be taken during the pumpingof each stage. Many changes in injection behavior


can be explained when these samples are analyzed.Fluctuations in injectivity may be due to a processproblem that was innocently incorporated for oper-ational expedience or safety compliance.

• Was an injection test with the appropriate fluidmade before pumping acid to establish a base injec-tivity before acidizing? Injection testing conductedwith platform or field equipment not intended forthis purpose can produce misleading results. Con-taminated fluids or poorly equipped monitoring canresult in bad data.

• Did the acid response during the injection validatethe damaging substance identified? HCl-solublescale may be revealed as the obvious contributor to the injectivity problem when large pressure dropsoccur when the HCl reaches the formation. If theinjection rate is increased, similar pressure dropscould also be noted when the HCl-HF mixturereaches the formation.

• Did the pressure response indicate good diversion?Pressure increases may be interpreted as diverteraction, but this is not always the case. Diverterresponse should coincide with the use of a diverter; ifnot, other parts of the process should be investigated.

• How long was the spent acid left in the well beforeflowback? Some secondary and tertiary reactionsrequire time to produce precipitates. Quick turn-around for flowback, not high production rates,lessens the potential for these reactions to createdamage. Most of these reactions result in damagethat is detected only after production is initiated.

• Were spent acid samples recovered and analyzed?Flowback fluid samples should be acquired regard-less of the volume of the treatment. These samplesshould be marked, with the date and time, total vol-ume recovered to that point and other pertinentdata, such as choke size, flowing tubing pressure,water cut and produced quantities.

• Were the production results consistent with the acidinjection pressure response? If the injection pres-sure declines too quickly, the acid treatment causesthe well to develop a vacuum. Once the well is

brought back on line, the production does notimprove because of limitations associated with thewellbore construction or production facilities.

• Was a pressure buildup test performed and inter-preted? A pressure test analysis is the definitivemethod to answer whether the treatment is a suc-cess or failure.

18-12. ConclusionsAcidizing sandstone formations is not an impossibletask, but it is not simple either. Success requires amethodical, systematic approach. It can be accom-plished without any detrimental effects by analyzingvital information. The flow chart in Fig. 18-6 showsthe steps the process encompasses.

The following conclusions can be made about sand-stone acidizing:

• Damage identification determines the types of acidsand other solvents to use in a sandstone acidizingtreatment.

• A knowledge of the chemical reactions involvedamong acids and formation minerals and connatefluids provides some guidelines for acid types, con-centrations and the sequence to prevent or reducethe precipitation of insoluble reaction products.

• The selection of appropriate types and volumes ofpreflushes and overflushes also helps prevent incom-patibilities between formation fluids and acid systems.

• A numerical simulator should be used to quantifyacid volumes, although simple guidelines are pro-vided to assist in the selection of treatment vol-umes. The most important factor in successful acidstimulation is to provide clean, filtered acids at theperforations by filtering all fluids and cleaning(pickling) the tubing before the acid treatment is injected into the formation.

• Evaluating the executed acid treatment providesinformation to improve subsequent acid treatmentsin the same or similar formations.



Figure 18-6. Sandstone acidizing treatment design process.

Well schematic

Coredata

PressuredataLogs

Evaluate as an acidizing candidateusing

NODAL analysis

Mechanicalproblems Acidizing

required

Liquidsamples

Laboratoryanalysis

No

No

No

Yes

Yes

Yes

Yes

Design processusing

expert system orsimulators

Equipment constraints:

1. Fluid

2. Fluid

3. Fluid

1. Stage

2. Stage

3. StagePrepare

equipment andmaterials and

instruct personnel

Is thechemistry

good?

How do the fluidsaffect cleanup?

Fluid design

Calculatecleanupflow rate

Record

Treatmentparameters

Monitor thejob

Finishjob

executionAlter job execution

Pumpthejob

Review and referencefor future work

Treatment requirements Location requirements Fluid system

Cleanupprocess

Documents

Acidificacion Arenas