sandstone reservoirs

IntroductionTreatment fluid selection in sandstone formations is highly dependent on the mineralogy of therock as well as the damage mechanism. Hydrofluoric (HF) acid is typically used to dissolve thedamaging silicate particles. Nonacid systems are sometimes used to disperse whole mud andallow it to be produced with the treating fluid. The criteria for selecting the treating fluid aremineralogy, formation damage mechanism, petrophysics and well conditions.

Formation mineralogyCompatibility and sensitivityCompatibility of the formation minerals to the various treating fluids and their additives is a sig-nificant issue when selecting fluids for acidizing. Compatibility implies that permeability doesnot decrease when the treating fluid contacts the formation. This concept of compatibilityapplies especially to sandstones, where potentially damaging reactions may occur.

Compatibility and sensitivity are related concepts. As stated by McLeod (1984), a successfulmatrix treatment depends on the favorable response of the formation to the treatment fluid. Thetreating fluid, therefore, must remove existing damage without creating additional damagethrough interactions with the formation rock or fluids. A formation is sensitive if the reactionbetween the rock minerals and a given fluid induces damage to the formation.

The sensitivity of a formation to a given fluid includes all the detrimental reactions that cantake place when this fluid contacts the rock. These detrimental reactions include the deconsol-idation and collapse of the matrix, the release of fines or the formation of precipitates. The pre-cipitation of some damaging compounds cannot be avoided. Treating and overflush fluid stagesare sized; so, there is sufficient volume to push potential precipitates deep enough into the reser-voir to minimize their effects because of the logarithmic relationships between pressure dropand distance from the wellbore.

Sandstones can be sensitive to acid depending on temperature and mineralogy. Ions of silicon,aluminum, potassium, sodium, magnesium and calcium react with acid and can form precipi-tates at downhole temperatures, once their solubility product is exceeded. If these precipitatesoccur in the near wellbore area, they can damage the formation. Sensitivity depends on the over-all reactivity of the formation minerals with the acid. Reactivity depends on the structure of the rock and the distribution of minerals within the rock, i.e., the probability of the acid reachingthe soluble minerals.

The sensitivity of sandstone will also depend on the permeability of the formation. Low-permeability sandstones are more sensitive than high-permeability sandstones for a given mineralogy. Acid formulations should be optimized on the basis of a detailed formation evaluation(Davies et al., 1992, Nitters and Hagelaars, 1990).

Fluid Selection Guide for Matrix Treatments ■ Sandstone Reservoirs 15

Sandstone Reservoirs

16 Fluid Selection Guide for Matrix Treatments

Sandstone petrographyFrom a mineralogical view, two factors affect the reactivity of a given mineral: chemical compo-sition and surface area. The composition and structure, the petrography, of the rock are impor-tant factors used to determine potential sensitivity. Figure 4-1 schematically represents thedifferent constituents of a common sandstone.

Rock structureTypically, sandstone reservoirs are made of a framework of silicate grains, such as quartz,feldspars, chert and mica. This framework is the originally deposited sand. Secondary minerals,precipitated in the original pore spaces, are the cementing materials for the grains (most fre-quently secondary quartz overgrowth or carbonates) and the authigenic clays. The main compo-nents of clay minerals are silicon and aluminum; hence, they are called aluminosilicates.

The actual solubility of various minerals in a sandstone reservoir depends strongly on theirposition in the structure of the rock. Only the mineral surfaces that can be contacted by the treat-ing fluid will be dissolved. The total specific surface area of the minerals affects their reactivitywith HF acids. The larger the surface area is, the more reactive the minerals are. Because of theirgreater specific area, clays react much faster than feldspars, and feldspars react much fasterthan quartz, especially in the presence of high proton (H+) concentrations. Table 3-1 in the chap-ter on formation damage lists the specific area of some common sandstone minerals.

Since they are usually the most reactive components, it is important to know the amounts ofthe various clay minerals in the rock. A petrographic study helps in understanding what responsewill result from pumping an acid and why. Chapter Six discusses petrographic studies in detail.

HCl solubility is commonly used to represent the carbonate content of the sandstone. A petro-graphic study can verify whether using HCl solubility is an acceptable estimate for carbonate.Other minerals, such as oxides, sulfides and chlorite clay, are also partially soluble in HCl.Overestimation of the amount of carbonate will affect fluid selection because HF acids are notused in sandstones with calcite content greater than 20%. A limit on carbonate content is neededto avoid the precipitation of calcium fluoride from the reaction of HF with calcite. Reservoirs withhigh calcite content are treated with HCl or organic acids, which are ineffective in dissolving clay and fines particles. If HCl solubility is used for calcite, but is too high because of other HClsoluble minerals, a sub-optimal fluid could be selected because of the assumption that an HF fluid cannot be used.

Figure 4-1. Constituents of sandstone.

Porosity-Filling Minerals

Secondary cement(carbonate quartz)

Clay(pore lining i.e. illite)

Clays(pore filling i.e. kaolinite)

Matrix Minerals

Quartz

Feldspars†

Chert†

Mica†

†Mud acid soluble/sensitive

Sandstone Reservoirs 17

ClaysThe distinction between clay types depends more on the arrangement of the atoms in their crys-talline structure than any major difference in their chemical formula. However, small differencesin chemical formula, e.g., the presence of iron, can lead to major problems during treatment. Thestructures of kaolinite, smectite, illite and chlorite are shown in Fig. 4-2. The structural differ-ences between the clays determine the surface area that is exposed to the reservoir fluids. Whileclay reactivity is a function of this surface area, the location of the clay in the rock matrix is alsocritical to its reactivity. Simply because the clay is in the rock does not mean that the clay isreactive.

Authigenic clays, which grow in the pores from minerals in the connate water (Wilson andPittman, 1977), can be pore filling or pore lining. Authigenic clays have a large amount of surfacearea exposed in the pore and can be reactive. Detrital clays, part of the building material in theoriginal matrix, are usually less reactive than authigenic clays, because they have less surfacearea in contact with the fluids in the pore.

Clay may also act as cement holding the matrix grains together. As a binder or cement, claymay react with fluids such as acid and water to deconsolidate the formation. If the clay cementis shielded by a quartz overgrowth, as is common in many sandstone formations, the clay will notbe reactive. Only authigenic clays, unprotected clay cements and the few detrital clays on thepore boundary can potentially cause damage. The common clays that account for most of the real

Figure 4-2. Photomicrographs of (a) pore-filling smectite sheets, (b) books of kaolinte platelets in a pore space, (c) honeycomb growth of chlorite on a sand grain (d) hairs of illite extending from a sand grain.

(a) (b)

(c) (d)

and perceived clay problems are kaolinite, smectite (montmorillonite), illite and chlorite.Fortunately, these minerals can be dissolved with HF acid; so, the damage can be treated. If for-mation collapse is a concern when unprotected clay cement is present, the recommended acidstrength would need to be adjusted.

In recent years, clay compatibility with hydrochloric acid (HCl) has become an issue. All clayshave a temperature at which they become unstable in HCl (Table 4-1). Unstable clays decomposequickly and consume all available HCl. Silica gel precipitates, which damage the matrix, are prod-ucts of the decomposition of these clays. Therefore, the presence of these specific clays can havea large influence on the ultimate fluid recommendation.

Chemistry of sandstone acidizingThe chemical reactions between sandstone minerals and HF acids have been extensivelydescribed in the literature. There are three classes of HF reactions: primary, secondary and tertiary.

Primary reactionsPrimary reactions describe the action of the unspent acid with the various minerals as follows:

The presence of calcium (Ca++) will cause calcium fluoride (CaF2+) to precipitate. Sodium

(Na+) and potassium (K+) can create alkali-fluosilicates and alkali-fluoaluminates when forma-tion minerals, or sodium or potassium brines, react with the hexafluorosilicic acid produced bythis reaction. The fluosilicate and fluoaluminate compounds are more likely to form during theinitial phases of the dissolution, since a high concentration of HF relative to the clay enhancesthe reaction. Precipitation of these compounds will occur when the amount present increasesabove the solubility limit.

Secondary reactionsSecondary reactions describe the action of the hexafluorosilicic acid with remaining acid and therock as follows:

The driving force for this reaction is the greater affinity of fluorine for aluminum than for


HF eral Al Si H AlF H SiF H Ox+ ( ) + → + ++ ++min , .2 6 2

H SiF eral Al Si H AlFx2 6+ ++ ( ) + → +min , silica gel.

Table 4-1. Clay instability in HCl acid (Simon & Anderson, 1990)

Mineral Maximum Temperature (°F [°C])

Zeolites 75 [24]

Chlorites 150 [65]

Illite 190 [87]

Mixed layer 200 [93]

Smectite 200 [93]

Kaolinite 250 [121]

silicon. Silica gel precipitation is well documented. This precipitation occurs when the initial HFis nearly consumed.

An exchange reaction occurs on the surface of the clays and fines to generate fluoaluminatesand silica gel. The silica is deposited on the surface of the mineral particles, and the fluoalumi-nates remain in solution. This precipitate is more like to occur when fast-reacting aluminosili-cates, such as clays, are present. The damaging effect of silica gel precipitates is still a point ofdebate; however, it does appear that they are more damaging at higher than lower temperatures.

Tertiary reactionsRecently there has been much discussion about whether tertiary reaction products are damaging tothe reservoir. Tertiary reactions are the reactions of the aluminum fluorides and aluminosilicates.

This reaction is due to the greater stability of AlFy over AlFx, which leads to continued reduc-tion of the F/Al ratio in spent HF until all remaining HCl is spent. The reaction is insignificant attemperatures below 194°F [90°C]. At higher temperature, the reaction can be considerabledepending on the stability of the formation clays with HCl. As the reaction drives on, and HF isspent, complex aluminofluorides may be precipitated out deep in the matrix. Gdanski andShuchart’s (1998) recommendations of 9%HCl:1%HF are based on these observations.

Other reactionsIron is another potential source of precipitation during sandstone acidizing. Precipitation is dueto the formation of colloidal ferric hydroxide as the acid spends (pH > 2). Sources of ferric iron(Fe3+) include some minerals (chlorite and glauconite clays) and tubing rust (iron oxide). Thesereactions begin to precipitate gelatinous ferric hydroxide at a pH of 2.2. The nature of the pre-cipitate (crystalline or amorphous) varies as a function of the anions present (Smith et al., 1969).Precipitation of ferric hydroxide during acid injection is normally not a problem, if an adequateHCl tubing wash was used to remove most of the soluble FeO2.

All acids used for matrix treatments should also contain iron control additives, either seques-tering or reducing agents or both. Ferrous iron (Fe2+) is typically not problematic, since ferroushydroxide precipitates at a pH between 7.7 and 9.

The main sources and causes of precipitates formed during sandstone matrix acidizing aresummarized in Table 4-2. The formation of these potentially damaging precipitates is affected bythe complex mineralogy of many sandstones. The likelihood of damage depends on several factors:■ Chemical—Are the reaction products soluble either in the overflush or the formation fluid?■ Crystallographic—Are the precipitates amorphous or crystalline?■ Morphological—Do they produce grains that can migrate, or do they cover undissolved particles?■ Concentration—Is the concentration high enough to cause plugging in the pore system?■ Physical—Is the damage potential also related to rock properties like permeability, pore size,

pore configuration or other reservoir characteristics?


AlF eral Al Si H AlF silica gel x yx y+ ( ) → + >+min , ;

Reaction frontSandstone acidizing reactions occur where the fluids meet minerals. As fluid is injected, the posi-tion of the zone where reactions take place moves radially outward from the wellbore. Figure 4-3represents this moving reaction front. The blue line shows the acid concentration relative to thereaction front. As the acid moves through the near wellbore region where all acid soluble miner-als have been dissolved, it retains its full strength. Acid spending takes place in the reactionfront. The radial width of this zone depends on the minerals present and the temperature of thereservoir at the point of contact, which is affected by any residual cool down effects due to dif-ference between fluid and rock temperature. When the injected fluid is totally spent, it movesthrough the unreacted minerals.

The primary reactions occur when fresh acid contacts fresh reservoir. This typically happensin the near wellbore region. As spent acid moves through this same matrix, the secondary andtertiary reactions occur with the reaction products precipitating further away from the wellbore.It is important to keep the injected fluid moving to carry reaction products past the criticalmatrix region of the well.


Figure 4-3. Moving front reaction.

Mineralsdissolved

Reactionfront

Unreactedminerals

Table 4-2. Possible precipitates in sandstone acidizing

Precipitate Origin

Calcium fluoride (CaF2) Carbonate-HF reaction CaF2 can be caused by an inadequate HCl preflush to remove calcium ions from calcite cementing materials orto flush calcium chloride completion fluids away from the near wellbore.

Amorphous silica Clay and silicate dissolution in HF. Amorphous silica results from both secondary and tertiary HF acidizing reactions.

Sodium and potassium fluosilicates Feldspar and illite clay dissolution in HF produce these primary reaction products. They can also form if seawater or sodium or potassium brinesare mixed with spent HF.

Sodium and potassium fluoaluminates Silico-aluminate dissolution in HF. Fluoaluminates, like the fluosilicates, occur when spent mud acid (H2SiF6) reacts with the formation. Theycan also form if seawater or sodium or potassium brines are mixed with spent HF.

Aluminum hyroxides and fluorides Clay and feldspar dissolution in HF can cause these precipitates.

Iron compounds Iron minerals or iron oxides (rust) can react with HCl-HF to produce these compounds.

Sandstone treatment designProper treatment design can be very effective in decreasing the negative effects of pumping acidsinto sandstone through the use of multiple injection stages and correct fluid selection. A typicalmatrix treatment in a sandstone will include a preflush, a main fluid and an overflush. When longintervals are treated, diversion stages are pumped after the overflush and before the next stageof preflush.

PreflushThe sequence of fluids used in a sandstone treatment is largely dependent on the damage type(s)being addressed. A preflush is a fluid stage pumped ahead of the main treating fluid. Multiple pre-flush stages are sometimes used to address multiple damage mechanisms and prepare the sur-face for the main treatment fluids.

In sandstone reservoirs, the acid preflush serves two purposes:■ To displace the formation brines, usually containing K, Na, or Ca ions, away from the wellbore

so there will be no mixing with HF acids. This decreases the probability of forming alkali-fluosilicates such as potassium hexafluorosilicate.

■ To dissolve as much of the calcareous material as possible, prior to injection of the HF acid tominimize calcium fluoride precipitation.

Due to reservoir heterogenities, it is unlikely that the acid preflush will remove all of the cal-cite. However, it has been shown that reducing calcite below 6% is sufficient to avoid precipita-tion (Fig. 4-4). Strength and volume guidelines are based on the criteria set up in the work doneby Labrid (1971), Fogler et al. (1976), Kline (1980), Kline and Fogler (1981) and Walsh etal.(1982). This theoretical work was further investigated and confirmed by fieldwork done byGidley (1985), McLeod (1984), Thomas and Crowe (1981) and others.

Using an additional ammonium chloride (NH4Cl) brine preflush for sandstone acid treatmentsis an emerging practice. This preflush conditions the formation clays as it moves formation wateraway from the near wellbore area. The NH4

+ ions in the brine exchange with the alkali (Na, K, orCa) ions on the clay particles; so, they will be displaced from contact with the mud acid. Theeffectiveness of this procedure appears to be controlled by the brine concentration at a radial dis-tance of 2.5 ft from the wellbore. This preflush is pumped at the start of the job to establish injec-tivity before the regular mud acid treatment is pumped. It is only pumped once and is not a partof the regular treating sequence.


Figure 4-4 . HCl/HF ratio to avoid precipitation, based on AlF3 and CaF2 precipitation(Walsh et al.,1982).

Max weightpercent ofHF in acidformation

Weight percent of HCl in acid formation

16

14

12

10

8

6

4

2

00 10 20 30 40

0% Calcite3% Calcite6% Calcite

Increasing weight percent of acid consuming mineralsleft by HCl preflush

Ideal case

Hydrocarbon solvents can be used to remove oil films and paraffin deposits; so, the aqueousacid systems can contact the surfaces of the mineral. These types of preflushes affect treatmentsuccess because the acid must contact the damage before it can react with it. A solvent preflushis typically not a part of the normal fluid staging. Like the brine preflush, it is pumped before thenormal acid treatment. If a diverter is necessary for better coverage, the diverter is pumpedbetween solvent slugs and before the first acid preflush.

Mutual solvents can also be added to preflush and overflush fluids. However, they must be thor-oughly tested for compatibility with the oil in place. Adding mutual solvents to the preflush willhelp remove oil from the near-wellbore region and leave the rock and damaging materials water-wet. This enhances the rate of acid attack. Mutual solvents can increase inhibitor requirements;so, all formulations must be tested before pumping.

Main fluidThe main fluid in a sandstone acid treatment is the fluid used to remove the damage. It is typi-cally a mixture of hydrofluoric (HF) and hydrochloric (HCl) or organic acids. HF acid is usedbecause it is the only common, inexpensive mineral acid able to dissolve siliceous minerals. It ismixed with HCl or organic acid to keep the pH low when it spends to aid in prevention of detri-mental precipitates. These mixtures are called mud acids because they were originally developedto treat siliceous drilling mud damage.

HF acid should not be used in sandstone formations with high carbonate content. The risk offorming calcium fluoride precipitates is too great, since it is unlikely that a sufficient amount ofHCl acid preflush can be pumped. The accepted cutoff point for the use of hydrofluoric acid is20% calcite + dolomite based on the guidelines developed by McLeod in 1984.

OverflushThe overflush is an important part of a successful sandstone acid treatment. It performs thefollowing functions:

■ displacement of the nonreacted mud acid into the formation■ displacement of the mud acid reaction products away from the wellbore■ removal of potential oil-wet relative permeability problems caused by some corrosion inhibitors.

The overflush fluid must be miscible with the acid in order to displace it. Therefore, aqueous-base liquids should be considered as the first displacing and flushing fluid. This may be followedby other fluid systems depending on the concerns and well conditions. Studies of displacementfronts indicate that the reactivity and fluid character of the overflush have a major influence onthe volume required to displace the spent mud acid. Recent experience indicates the advantageof including HCl or acetic acid in the first part of the overflush to maintain a low-pH environmentfor the displaced spent mud acid stage.

The minimum total overflush volume should provide at least 3 ft of radial penetration into theformation to move potential problems past the critical matrix where the greatest pressure dropoccurs. Damage effects are minimized beyond the critical matrix because of the logarithmic rela-tionship between pressure drop and distance from the wellbore. Volumes that are less than twicethe mud acid stage volume should be considered inappropriate. Formation permeability ani-sotropy may require doubling or even tripling this volume, if the reservoir pressure is sufficientto unload the injected fluid.

Large overflushes help prevent the near wellbore precipitation of amorphous silica. At forma-tion temperatures of 200°F [93°C] or greater, amorphous silica precipitation occurs while themud acid is being pumped into the formation. The precipitate is somewhat mobile at first, but itcan set up as a gel after flow stops. If this potentially damaging material is kept moving by theoverflush fluid, it will be diluted and moved beyond the critical matrix.


Sandstone treatment fluid selectionFluid selection rules for each stage of the treatment must consider all of the parameters previ-ously discussed: dissolution of damage, compatibility with rock minerals and reservoir fluids andpotential damaging reaction products. The rules for the selection of acids are shown below, andthey are the same as those in the Fluid Selection Advisor (FSA) of the StimCADE design program.The main selection criteria are the formation mineralogy and permeability. The selection ofnonacid fluids for treating damages such as organic deposits, wettability changes and water blockwill be discussed at the end of this chapter.

Formation lithology affects the selection of acid strength. Since silts and clays are the com-ponent minerals that react with HF acid to cause potentially damaging precipitates, the higherthe silt and clay content, the greater risk of precipitation. Increasing the HCl:HF ratio is one wayto retard precipitation. HCl increases the dissolving power of the HF and a low-HF contentreduces the precipitation of silica. Therefore, as the silt and clay content of the formationincreases, the recommended HCl:HF ratio also increases. The presence of HCl sensitive clays willalso affect the type of acid chosen.

X-ray diffraction (XRD) analysis is the most common test used to determine formation miner-alogy. However, this data is not always available. Formation solubility in both HCl and HCl:HF canbe used to approximate the total silt and clay content. The difference in these solubilities corre-lates well to silt and clay content by XRD analysis as seen in Table 4-3. Solubility information,however, does not indicate the type of clay present.

Permeability affects acid selection by influencing the amount of damage caused by acid precipitates. A low-permeability formation will be more severely damaged by precipitates than aformation with high permeability. Therefore, weaker acids, which help limit precipitation, arerecommended for lower permeability formations.

Brine preflush or overflushThe NH4Cl brine concentration used in a sandstone acid treatment is based on obtaining a 3%NH4Cl solution at a distance of 2.5 ft from the well when a volume of 50 gal/ft is pumped. The cal-culation considers the cation exchange capacity of the various silt and clay components in theformation. The recommended brine concentration is calculated automatically in the StimCADEFSA module, or the following equation can be used:

(Be sure and add the smectite and illite in mixed layer clays to their respective totals.)


Table 4-3. XRD Versus Solubility Analysis

Formation Silt and Clay Difference in Solubility from XRD (%) between HCl and HCl:HF (%)

Muddy sand 7.0 5.2

Brazos sand 13.6 13.0

Miocene A 25.0 20.7

Miocene B 26.0 22.1

Miocene C 34.0 33.6

Concentration smectite illite kaolinite

chlorite feldspar

= + ×( ) + ×( ) + ×( )+ ×( ) + ×( )

3 0 3 0 12 0 08

0 12 0 05

% . % . % .

% . % .

A minimum concentration of 3% NH4Cl is used if no clays are present. From the equation, it isobvious that the amount of smectite present in the rock has the most effect. If smectite is pre-sent, even if the amount isn’t known, use a higher concentration of NH4Cl. If the core flow testsexhibit sensitivity to water, smectite should be suspected.

Acid preflush or overflush The acid used as a preflush or an overflush to a main treatment containing hydrofluoric aciddepends on the silt and clay content of the formation, its permeability and the presence of HClsensitive minerals, like chlorite, glauconite and zeolites. Table 4-4 lists the acid preflush recom-mendations. For operational simplicity, the same acid is used for both pre- and overflush.

Organic acids are recommended for use in conjunction with, or instead of, HCl in sensitive for-mations. Although they will dissolve the carbonate, they work more slowly. When pumpingorganic acids as stand-alone fluids, they should be mixed in ammonium chloride rather thanfresh water. Organic acids also act as a low-pH buffer and complexing agent that helps minimizethe tendency of iron compounds to precipitate as the acid spends. However, they do not dissolveiron scale or prevent clay swelling.


Table 4-4. Acid Preflush and Overflush Selection

Lithology Criteria (%) Permeability (mD) Acid Concentration

Zeolites Chlorite + Silt and ClayGlauconite

>2 Any Any Any 10% Acetic

≤2 >6 Any Any 10% Acetic

≤2 3–6 >10% silt or >10% clay Any 5% HCl + 5% Acetic

≤2 3–6 <10% silt and <10% clay Any 7.5% HCl + 5% Acetic

0–2 ≤3 >10% silt or >10% clay >100 10% HCl + 5% Acetic

0–2 ≤3 <10% silt and <10% clay >100 15% HCl + 5% Acetic

0–2 ≤3 >10% silt or >10% clay 20–100 7.5% HCl + 5% Acetic

0–2 ≤3 <10% silt and <10% clay 20–100 10% HCl + 5% Acetic

0–2 ≤3 >10% silt or >10% clay ≤20 5% HCl + 5% Acetic

0–2 ≤3 <10% silt and <10% clay ≤20 7.5% HCl + 5% Acetic

0 ≤3 >10% silt or >10% clay >100 10% HCl

0 ≤3 <10% silt and <10% clay >100 15% HCl

0 ≤3 >10% silt or >10% clay 20–100 7.5% HCl

0 ≤3 <10% silt and <10% clay 20–100 10% HCl

0 ≤3 >10% silt or >10% clay ≤20 5% HCl

0 ≤3 <10% silt and <10% clay ≤20 7.5% HCl

Main treatment fluidDetermining the proper blend of HCl and HF to use in a mud acid mixture, and whether HCl ororganic acid is used, is a complex process. The selection depends on the silt and clay content ofthe formation, its permeability and the presence of HCl sensitive clays. The criteria are similarto those for choosing the acid preflush or overflush concentration. Table 4-5 lists the recommen-dations based on these parameters.

Table 4-5. Mud Acid Selection

Lithology Criteria (%) Permeability (MD) Acid Concentration

Zeolites Chlorite + Silt and ClayGlauconite

>5 Any >10% silt and >10% clay >20 OCA HT

>5 Any >10% silt or >10% clay >20 OCA HT

>5 Any <10% silt and <10% clay >20 OCA HT

>5 Any >10% silt and >10% clay ≤20 OCA HT

>5 Any >10% silt or > 10% clay ≤20 OCA HT

>5 Any <10% silt and <10% clay ≤20 OCA HT

2–5 3–6 >10% silt and >10% clay >20 OCA

2–5 3–6 >10% silt or >10% clay >20 OCA

2–5 3–6 <10% silt and <10% clay >20 OCA

2–5 3–6 >10% silt and >10% clay ≤20 OCA

2–5 3–6 >10% silt or >10% clay ≤20 OCA

2–5 3–6 <10% silt and <10% clay ≤20 OCA

≤2 >9 >10% silt and >10% clay Any OCA HT

≤2 >9 >10% silt or >10% clay Any OCA HT

≤2 >9 <10% silt and < 10% clay Any OCA HT

≤2 6–9 >10% silt and >10% clay >20 OCA HT

≤2 6–9 >10% silt or >10% clay >20 OCA HT

≤2 6–9 <10% silt and <10% clay >20 OCA HT

≤2 6–9 >10% silt and >10% clay ≤20 OCA HT

≤2 6–9 >10% silt or >10% clay ≤20 OCA HT

≤2 6–9 <10% silt and <10% clay ≤20 OCA HT

≤2 3–6 >10% silt and >10% clay >20 9 % HCl + 1% HF + 5% Acetic

≤2 3–6 >10% silt or >10% clay >20 9 % HCl + 1.5% HF + 5% Acetic

≤2 3–6 <10% silt and <10% clay >20 8 % HCl + 2% HF + 5% Acetic

≤2 3–6 >10% silt and >10% clay ≤20 4.5 % HCl + 0.5% HF + 5% Acetic

≤2 3–6 >10% silt or > 10% clay ≤20 6% HCl + 1% HF + 5% Acetic

≤2 3–6 <10% silt and <10% clay ≤20 6% HCl + 1.5% HF + 5% Acetic

0–2 ≤3 >10% silt and >10% clay >100 13.5% HCl + 1.5% HF + 5% Acetic

0–2 ≤3 >10% silt or >10% clay >100 12% HCl + 2% HF + 5% Acetic

0–2 ≤3 <10% silt and <10% clay >100 12% HCl + 3% HF + 5% Acetic

0–2 ≤3 >10% silt and >10% clay 20–100 9% HCl + 1% HF + 5% Acetic

0–2 ≤3 >10% silt or >10% clay 20–100 9% HCl + 1.5% HF + 5% Acetic

0–2 ≤3 <10% silt and <10% clay 20–100 8% HCl + 2% HF + 5% Acetic

0–2 ≤3 >10% silt and >10% clay ≤20 4.5% HCl + 0.5% HF + 5% Acetic

0–2 ≤3 >10% silt or >10% clay ≤20 6% HCl + 1% HF + 5% Acetic

0–2 ≤3 <10% silt and <10% clay ≤20 6% HCl + 1.5% HF + 5% Acetic

0 ≤3 >10% silt and >10% clay >100 13.5% HCl + 1.5% HF

0 ≤3 >10% silt or >10% clay >100 12% HCl + 2% HF

0 ≤3 <10% silt and <10% clay >100 12% HCl + 3% HF

0 ≤3 >10% silt and >10% clay 20–100 9% HCl + 1% HF

0 ≤3 >10% silt or >10% clay 20–100 9% HCl + 1.5% HF

0 ≤3 <10% silt and <10% clay 20–100 8% HCl + 2% HF

0 ≤3 >10% silt and >10% clay ≤20 4.5% HCl + 0.5% HF

0 ≤3 >10% silt or >10% clay ≤20 6% HCl + 1% HF

0 ≤3 <10% silt and <10% clay ≤20 6% HCl + 1.5% HF


The cleaner the sandstone (lower silt and clay content) and the higher the permeability, thelower the HCl:HF ratio, and the more aggressive the treatment can be. Typically, the HCl:HF ratiois either 4:1, 6:1, or 9:1. A higher volume of weak acid must be pumped to attain the same resultsas a smaller volume of a stronger acid. This is an important consideration when designing treat-ments for environmentally sensitive areas where disposing spent acids can create problems.

The ratio of HCl:HF should be increased if the formation contains clay rather than calcitecementing materials. Pick the acid concentration recommended in Table 4.5. If the HCl:HF ratiois less than 9:1, change the recommendation to the 9:1 ratio that contains a lower HF content.For example, if a 6:1 HCl:HF fluid is normally used, change to a 4.5:0.5 HCl:HF mixture.

Mud acids should only be used in formations with less than 20% carbonate (calcite +dolomite) because of the increased risk of forming damaging calcium fluoride precipitates athigher carbonate content. HCl or acetic acids are used for these formations. The specific acidused is dependent upon reservoir temperature and the presence of HCl sensitive clays as shownin Table 4.6.

Sandstone treatment fluid recommendations are automatically determined in the FSA of theStimCADE matrix design program. All rules and special cases discussed in this book are part of thiscomputer program, which will also make diverter recommendations.

Specialty acidsClayACIDClayACID* treatment is a sandstone acidizing system employing fluoboric acid (HBF4). ClayACIDtreatment not only provides good stimulation but also provides permanent stabilization of claysand other fines as well as eliminating water sensitivity and the mobility of migratory fines(Thomas and Crowe, 1981). The acid slowly releases HF in situ through the hydrolysis of HBF4according to the following reaction:

At any given time, there is only a limited amount of hydrofluoric acid available. The acid is con-sumed by reaction on clay minerals followed by hydrolysis of fluoboric acid to produce more HF.Therefore, ClayACID fluid is a retarded acid and can penetrate to a much greater distance fromthe wellbore before spending than mud acid can.

At higher temperatures, >150°F [65°C], the kinetics of hydrolysis is rapid. Equilibrium con-ditions dictate that there is only a limited amount of HF present in solution at any given time. Forexample, at 212°F [100°C] only 0.15% HF is present. Thus, the reaction rate is similar to a verydilute mud acid solution. The result of having such a limited amount of HF available is adecreased probability of forming precipitates of fluosilicates, fluoaluminates or silica.

A major advantage of the ClayACID system is its ability to inhibit the migration of formationfines. Depending on the mineral attacked, partial dissolution takes place, and boron is includedin the lattice of the mineral crystal. As a result of this topochemical reaction, borosilicate reac-tion products coat the mineral surface. The coating does not plug the pores but desensitizes theminerals and stabilizes fines particles by fusing them to the sand grains.


Table 4-6. Acid Selection for High Calcite Sandstones

Chlorite + Glauconite Reservoir Temperature (°F [°C]) Acid Recommendation

>0 >200 [93] 10% Acetic

>0 ≤200 [93] 10% HCl

0 >300 [148] 10% HCl

0 ≤300 [148] 15% HCl

HBF H O HBF OH HF4 2 3+ → +

ClayACID can be used as an alternative to mud acids in formations that show severe slough-ing when treated with mud acid. Clay Acid is also recommended for severe fines migration, whichis indicated by rapid declines in production that can be as large as 50percent in 6 months. Whenused for this application, it is pumped as an overflush to a mud acid treatment.

There are two ClayACID formulations. Use ClayACID regular for reservoir temperatures up to300°F [148°C]. Use ClayACID LT for reservoir temperatures to 130°F [54°C], but not for tem-peratures above that. When pumping ClayACID fluids, displace the fluid just into the formation. Do not overflush! To obtain the maximum stabilization effect, the ClayACID feature should reactand coat the clays in the critical matrix portion of the reservoir. The well should also be shut inafter pumping ClayACID fluid due to its longer reaction time. Table 4-7 lists minimum shut-intimes by temperature.

Organic clay acidIn cases where high concentrations of acid sensitive clays, such as zeolite, chlorite or glauconite,are present, specialized acids, like OCA* Organic Clay Acid) are available. This acid system canalso be used when acidizing sandstone formations with very high-bottomhole temperatures orwhen the total clay content of the formation is greater than 30%. OCA formulations are mixturesof an organic acid and fluoboric acid. When used in matrix acidizing applications, OCA fluid

■ removes formation damage caused by clay and other aluminosilicate minerals■ minimizes hydrated silica precipitation, which is known as the secondary reaction■ prevents migration of undissolved fines post acidizing treatments■ treats high-temperature sandstone wells. OCA fluids can be used at temperatures ranging

from 80°F to 400°F [27°C to 204°C].

There are two formulations recommended for different conditions. The first formulation, OCA-Regular, is used for temperatures lower than 350°F [176°C] or in formations containing lowconcentrations of HCl sensitive minerals. The second formulation, OCA-HT, is intended for sand-


Table 4-7. ClayACID Shut-In Time

BHST (°F [°C]) Min Shut-In Time (hr)

Regular ClayACID ClayACID LT

100 [37] 96 48

110 [43] 76 38

120 [48] 52 26

130 [54] 35 18

140 [60] 24 Not recommended








300 [148] 0.5 Not recommended

stone formations with temperatures 350°F [176°C] and above or in formations containing morethan 5% of zeolite or chlorite.

When considering this fluid, crude oil compatibility testing is required. If an incompatibilityexists, OCA fluids may form a thick, rigid emulsion that will inhibit cleanup of the formation. Thisproblem appears to be most commonly associated with highly paraffinic crudes.

Mud and silt removerMSR* mud and silt remover, which dissolves, disperses and suspends damaging particles andfines, can be formulated with HCl/HF mixtures. Naturally fractured sandstone is a very hard, com-pact, low-porosity and low-permeability formation. The reservoir productivity usually comes fromthe fracture system. These fractures can be plugged with drilling solids. MSR fluids can be usedin these types of formations where the plugging particles are located in natural fissures or inhydraulically induced fractures.

MSR formulation is determined using the same criteria as a normal sandstone main treatingfluid. However, if organic acids are required due to extreme high temperature or sensitive clays,consult the regional technical specialist or laboratory. MSR is not normally formulated usingorganic acids.

Dynamic acid dispersionDAD* dynamic acid dispersion, is an acid outside-phase emulsion prepared and stabilized withDispersing Agent U74. The purpose of the dispersion is to simultaneously dissolve acid-solubleminerals and remove oily paraffinic deposits. Target areas can be tubulars, perforations or thecritical matrix. DAD can be used as a preflush ahead of mud acid or ClayACID during matrixtreatment procedures. This low-viscosity dispersion allows one-stage cleanup and acidizing ofhydrocarbon-coated formations, gravel packs, wellbores and tubulars. Various ratios of acid andhydrocarbon solvent are possible with common dispersions ranging from 90% acid and 10%organic solvent to 50% acid and 50% organic solvent.

NARS fluidNARS* fluids are special treating solutions that contain no acid. These fluids are used as cleanupand breakdown fluids in formations that may be damaged by acid. These solutions are nondam-aging to water- or acid-sensitive formations and contain strong chelating and clay suspendingagents. They can be used in high-temperature reservoirs (greater than 400°F [204°C]) but shouldnot be used if downhole temperatures are below 100°F [37°C]. Two solutions, NARS 200 andNARS201, are currently being used.


Nonacid treatmentsSolvents, bleach and other nonacid fluids are used to treat specific damage mechanisms. Thedamages and recommended fluids are outlined in Table 4-8.


Table 4-8. Recommendations for Nonacid Fluids

Damage Mechanism Recommendation

Asphaltenes or paraffin Xylene

Bacteria Formation Cleaning Solution (M91) followed by acid treatment

Emulsion block or injection carryover of emulsion CLEAN SWEEP*†

Injection carryover of oil CLEAN SWEEP†

Mixed organic and inorganic scale deposits DAD†

Water block CLEAN SWEEP†

Wettability alteration CLEAN SWEEP†

† Consult Matrix Materials Manual for CLEAN SWEEP or DAD recommendation for specific well conditions.

sandstone reservoirs

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