Acidizing

Chapter 54

Acidizing A.W. Coulter Jr., Dwell-Schlumberger

A.R. Hendrickson, Dowell-Schlumberger

S.J. Martine2.u. of Tulsa *

Introduction The use of acids to stimulate or to improve oil production from carbonate reservoirs was first attempted in 1895. Patents covering the use of both hydrochloric and sulfur- ic acids for this purpose were issued at that time. Although several “well treatments” were conducted, the process failed to arouse general interest because of severe corrosion of well casing and other metal equipment, The next attempts to use acid occurred between 1925 and 1930. These consisted of using hydrochloric acid (HCl) to dissolve scale in wells in the Glenpool field of Oklahoma and to increase production from the Jefferson Limestone (Devonian) in Kentucky. None of these efforts were successful and “acidizing” once again was abandoned.

The discovery of arsenic inhibitors, which allowed HCl to react with the formation rock without seriously damaging the metal well equipment, revived interest in oilwell acidizing in 1932. At that time, Pure Oil Co. and Dow Chemical Co. used these inhibitors with HCl to treat a well producing from a limestone formation in Isabella County, MI. Results of this treatment were outstanding. When similar treatments in neighboring wells produced even more spectacular results, the acidizing industry was born.

Throughout the years following those early treatments, the acidizing industry has grown to one using hundreds of millions of gallons of acid applied in tens of thousands of wells each year. Technology has developed with increasing rapidity, and many changes and innovations have been made to improve the effectiveness of acidizing treatments. Because of new techniques of application and development of additives to alter the characteristics of the acid itself, acidizing has become a highly skilled science. A knowledge of available materials, chemical reactions

‘Authors of the OrigInal chapter on this topic I” the 1962 editlon Included th!s aulhor (deceased). P E. Rlzgerald. and Harold E Staadt

at treating and well conditions, reservoir properties, and rock characteristics are required to design an effective and efficient acidizing treatment. Since it is beyond the scope of this text to cover all aspects of acidizing in detail, this discussion will be limited to a general description of materials, techniques, and design considerations. A bibli- ography is provided for those requiring a more detailed discussion of a particular subject. Also, the major well stimulation companies providing acidizing services offer literature and technical assistance for problem analysis and treatment design.

General Principles The primary purpose of any acidizing treatment is to dissolve either the formation rock or materials, natural or induced, within the pore spaces of the rock. Originally, acidizing was applied to carbonate formations to dissolve the rock itself. Over a period of time, special acid formulations were developed for use in sandstone formations to remove damaging materials induced by drilling or completion fluids or by production practices.

There are two primary requirements that an acid must meet to be acceptable as a treating fluid: (1) it must react with carbonates or other minerals to form soluble products, and (2) it must be capable of being inhibited to prevent excessive reaction with metal goods in the well. Other important considerations are availability, cost, and safe- ty in handling. While there are many formulations available, only four major types of acid have found extensive application in well treatments: hydrochloric, hydrofluoric, acetic, and formic acids.

Hydrochloric Acid (HCI)

An aqeuous solution of HCl is most commonly used for acidizing treatments, for reasons of economy and because it leaves no insoluble reaction product. When HCl is

54-2 PETROLEUM ENGINEERING HANDBOOK

I T 3500

In I

/ 3000 16

I4

12

IO

n

b

4

2

0 0 4 n I2 16 20 24

STRENGTH OF ACID, PERCENT BY WEIGHT

Fig. 54.1-Solution of limestone in acid.

TABLE 54.1~-HYDROCHLORIC ACID DENSITY AT 6O“F

% HCI Specific Gravity' "Baume** lbmlgal psilft depth

1.00 1.0048 0.7 8.377 0.4351 2.00 1.0097 1.4 8.418 0.4372 3.00 1.0147 2.1 8.460 0.4392 4.00 1.0197 2.8 8.501 0.4415 5.00 1.0248 3.5 8.544 0.4437 6.00 1.0299 4.2 8.586 0.4459 7.00 1.0350 4.9 8.629 0.4482 8.00 1.0402 5.6 8.672 0.4504 9.00 1.0447 8.2 8.710 0.4524 10.00 1.0500 6.9 8.754 0.4547 11.00 1.0550 7.6 8 796 0.4568 12.00 1.0600 8.2 8.837 0.4590 13.00 1.0646 8.8 8.876 0.4610 14.00 1.0702 9.5 8.922 0.4634 15.00 1.0749 10.1 8.962 0.4654 16.00 1.0801 10.8 9.006 0.4677 17.00 1.0849 11.4 9.045 0.4698 18.00 1.0902 12.0 9.089 0.4721 19.00 1.0952 12.6 9.132 0.4743 20.00 1.1002 13.2 9.171 0.4764 21.00 1.1057 13.9 9.218 0.4788 22.00 1.1108 14.5 9.261 0.4810 23.00 1.1159 15.1 9.303 0.4832 24.00 1.1214 15.7 9.349 0.4855 25.00 1.1261 16.3 9.385 0.4876 26.00 1.1310 16.9 9.433 0.4899 27.00 1.1368 17.5 9.478 0.4922 28.00 1.1422 18.0 9.523 0.4946 29.00 1.1471 18.6 9.563 0.4967 30.00 1.1526 19.2 9.609 0.4991 31.00 1.1577 19.8 9.663 0.5012 32.00 1.1628 20.3 9.694 0.5035 33.00 1.1680 20.9 9.738 0.5057 34.00 1.1727 21.4 9.777 0.5078 35.00 1.1779 21.9 9.820 0.5100 36.00 1.1827 22.4 9.860 0.5121 37.00 1.1880 22.9 9.924 0.5144 38.00 1.1924 23.4 9.941 0.5163 39.00 1.1963 23.8 9.974 0.5180 40.00 1.2008 24.3 10.011 0.5199 41.00 1.2053 24.7 10.049 0.5219

145

pumped into a limestone formation, a chemical reaction takes place, producing calcium chloride, CO*, and water. This reaction is represented by the following equation:

One thousand gallons of 15% HCI will dissolve approximately 10.8 cu ft (1,840 lbm) of limestone. It will liber- ate approximately 7,000 cu ft of CO1 , measured at atmospheric conditions, and produce 2,042.4 lbm of calcium chloride. This salt is dissolved in the original water of the acid solution, plus 39.75 gal of water formed during the reaction. The specific gravity of this solution will be 1.181 (20.4% calcium chloride). While 15 wt% HCI has been the most commonly used, concentrations of 20 and 28% have become extremely popular over the past 2 decades. Regardless of the acid strength used, the reaction is the same and equivalent amounts of carbonate rock are dissolved. For example, 10,000 gal of 3% HCl solution will dissolve the same amount of rock as 1,000 gal of 28% HCl. Fig. 54.1 shows the effect of acid concentration on the amount of limestone dissolved. The main differences between the two solutions are their reaction rates (or spending times) and their physical volumes. Although lower concentrations of acid have greater equivalent volumes, their reaction times and depth of penetration into the reservoir, from the wellbore, are con- siderably less than those of the higher-strength solutions. Reaction rates and penetration will be discussed later.

Similar reactions occur when dolomite or impure limestone is treated with HCI. Dolomitic lime contains a large percentage of magnesium combined as calcium magnesium carbonate. Although it reacts more slowly, this min- eral also dissolves in HCl, and the resulting magnesium chloride is soluble in the spent acid. Other impurities oc- curring in limestone and dolomite are often insoluble in acid, and if appreciable percentages of such components are present, special additives must be included in the acid solution to ensure their removal.

HCl ordinarily is manufactured in concentrations of 32 to 36 wt% HCl and is diluted at service company stations to 15, 20, or 28% for field use. The concentrated acid, the various chemical additives, and water are mixed in the tank truck used to haul the acid to the wellsite. Table 54.1 lists the weights of various concentrations of HCI. These data are useful in calculating mixing proportions for acid dilution, using the following equation:

vl-0 = vda cda 7 da

Cca(HCI)Yca '

where V/da = final volume of dilute acid,

cdd = desired concentration of dilute acid,

?'du = specific gravity of dilute acid, V,, = volume of concentrated acid required,

Cccr(HCI) = percent of HCI in concentrated acid, and ycO = specific gravity of concentrated acid.

Approximate proportions of concentrated acid and water required for dilution are shown in Fig. 54.2.

ACIDIZING 54-3

Determination of acid strength can be estimated in the field using either a hydrometer or a field titration kit. The accuracy of hydrometer readings depends on the care and technique used by the field engineer. Both the hydrometer and the glass cylinder in which the test is made should be free from oil or dirt. The spindle should float freely in the acid, and all readings should be made at the lowest level of the acid meniscus. The temperature of the acid sample should be taken and the hydrometer reading cor- rected to 60°F.

Determination of acid strength by titration is simplified by the use of 0.59 N standard sodium hydroxide solution. If a 2-mL sample of the acid is titrated with this standard solution to a methyl orange end point, the burette reading (milliliters of sodium hydroxide used) will be equal to the acid strength (percent HCI).

Acetic and Formic Acids

Acetic acid (CH3COOH) and formic acid (HCOOH) are weakly ionized, slowly reacting, organic acids. They are used much less frequently than HCI and are suitable primarily for wells with high bottomhole temperatures (BHT’s above 250°F) or where prolonged reaction times are desired. The reaction of these acids with limestone is described by the following equation:

2HOrg+CaCOj +CaOrgz +HzO+CO,.

HAc is available in concentrations up to 100% as glacial HAc. while HCOOH is available in 70 to 90% concentrations. For field use, HAc solutions normally are diluted to I5 % or less.

Above this concentration, one of the reaction products, calcium acetate, can precipitate from its “spent acid” solution because of its limited solubility. Similarly, the concentration of HCOOH normally is limited to 9 to 10% because of the limited solubility of calcium formate. At a 10% concentration, 1,000 gal HAc will dissolve 740 Ibm of limestone, whereas 1,000 gal HCOOH dissolves 970 lbm. Where more dissolving power per gallon of acid is desired, HCI is sometimes mixed with HCOOH or HAc. Such blends still provide extended reaction times. when compared with HCl. HCOOH and HAc also may be blended together. Table 54.2 illustrates some of the more common acid strengths and blends.

Hydrofluoric Acid (HF)

HF is used in combination with HCI and has been referred to as “intensified acid” or “mud removal” acid. depending on the formulation and use. HF is used primarily to remove clay-particle damage in sandstone formations, to improve permeability of clay-containing formations, and to increase solubility of dolomitic formations. Its utility is based on the fact that some clays. silica, and other materials normally insoluble in HCI have some degree of solubility in HF. For example, I .OOO gal of an acid solution containing 3% HF and 12% HCI will dissolve 500 lbm of clay and up to I .450 lbm of CaC03,

4HF+SiO? -tSiFJ +2H10

and

ZHF+SiF,+HzSiF,.

FORMULA FOR MIXING ACID IN ANY DESIRED CONCENTRATION:

VOLUME OF STRONG = (VOL OF WEAK) (%WEAK) (SF? GR.OF WEAK)

(=&OF STRONG) (SF’. GR.OF STRONG) GALLONS OFCONCENTRATED

t 7 HYDROCHLORIC ACID TO MAKE

1,000 GALLONS OF DILUTE ACID -8 -9

&

- 32 - 30 -28

3 s-23

’ 2: Q-20

2-I; -17

k-16 Z-15 =-I4

- 13

k-12

- IO

-II $?

-12 1 -13 0 -14 2

I5 a -16 z -17 0

-189 E -2om

-2&

2,

EKBG -282 :3oE : 32 z -34w :36g 1380 -400

Fig. 54.2-Dilution of concentrated HCI

TABLE 54.2-DIFFERENT ACIDIZING SOLUTIONS

Acid Concentration

Type

Relatwe CaCO, Eouivalent Reaction (Ibm/l,i)OO bal acid) time’

7.5 HCI 890 0.7 15 HCI 1,840 1.0 28 HCI 3,670 6.0 36 HCI 4,860 12.0 10 Formic 910 5.0 10 Acetlc 710 12.0 15 Acetic 1,065 18.0

7.5 Formic/ 14 HCI mixture 2,420 6.0

IO 14

Acetic/ HCI mixture 2,380 12.0

8 Formic/ 14 Acetic mixture 1,700 18.0

‘Approwlmale time for acid react!on 10 be COmpleled ( %qx?nl ‘) to an equ~vaienf strength of 2 5% HCI solution Values are compared by using spending lime 01 15% HCI as 1


0.4 I I I

\-MUD ACID 0.3 7’

0.2 I

0. I

0 /-REGULAR ACID

I I I I I 0 6 12 18 24

TIME OF CONTACT IN HOURS

Fia. 54.3-Solubilitv of bentonite in mud removal acid

Figs. 54.3 and 54.4 compare solubilities of bentonite and silica in HCl and HF acids.

In carbonates, application of HF/HCl mixtures must be controlled carefully because of cost and possible precipitation of reaction products such as calcium fluorides or complex fluosilicates, which have a very limited solubility. For reaction with silicates, such as natural clays or clays in drilling fluids, the blends usually contain 2 to 10% HF and 5 to 26% HCI. The concentration of HCl used in the blend should be equal to or greater than that of the HF.

The so-called “intensified acids” used in dolomitic formations are mainly HCl containing small concentrations of HF, usually about 0.25 % Intercrystalline films of silica, insoluble in HCl, often occur in the crystal structure of dolomite. When such are present, they prevent the acid from contacting the soluble portions of the rock. The presence of fluoride intensifier in the acid will destroy such films, allowing the acid to react more completely with the soluble portions of the rock. Fig. 54.5 illustrates the comparative reaction rates of HCI and intensified acid on dolomite formations.

More recent developments of HF involve the use of delayed-action agents in sandstone acidizing. The first of these was a self-generating mud acid system, reported by Templeton er al. ’ The system provides slow generation of acid from the hydrolysis of methyl formate. yielding methyl alcohol and HCOOH acid. The acid then reacts with ammonium fluoride to yield HF in situ. They attrib- ute the success of the system to getting the HF reaction away from the wellbore into areas that conventional HF solutions normally do not reach before spending. Equal- ly important factors are the techniques of application and of returning the well to production following treatment. The treatment technique mvolves use of an aromatic solvent and mud acid preflush, along with the self-generating mud acid (SGMA). The wells are returned to production by opening the choke gradually over a 90-day period and never allowing an excessive drawdown. The process is available from most service companies as SGMA.

A significant development in this area of slow-reacting, HF-supplying, clay-dissolving acid has been the fluoboric acid system reported by Thomas and Crowe.’ This acid

; 0.41 I I I

z 0.3u

2 TIME OF CONTACT IN HOURS 1

Fia. 54.4-Solubilitv of silica sand in mud removal acid

hydrolyzes to form hydroxyfluoboric acid and HF, which will dissolve clays.

HBF4 +HZO-‘HBF30H+HF.

This reaction provides a slow-release source of HF, which can penetrate deeply before spending. Perhaps more important, the slowly generated hydroxyfluoboric acid reacts with clays to form a nonswelling, nondispersing product that stabilizes fine clays and holds fine particles of silica in place.

Acid Reaction Rates A knowledge of the factors affecting the reaction rate of acids is important for several reasons. First, these factors, correlated with reservoir and formation characteristics, form a guide for the selection of acid type and volume for a given treatment. Next, a study of these factors can furnish an understanding of what parameters govern spending time, which will determine how far a given formulation can penetrate into the formation before spending. Many factors govern the reaction rate of an acid, such as pressure, temperature, flow velocity, acid concentration, reaction products, viscosity, acid type, area/volume ratio, and formation composition (physical and chemical). These factors have been the subject of ex- tensively reported research for many years. Details of such studies are available in published literature. Only a brief general discussion will be presented here.

Pressure Fig. 54.6 shows the effect of pressure on the reaction rate of 15% HCl with limestone and dolomite at 80°F. Above 500 psi, pressure has little effect on reaction rate. At bottomhole treating pressures, there is only a small difference (a factor of 1.5 to 2) in the comparative reaction of acid with limestone and dolomite compared to the rather large difference (a factor of about 10) at atmospheric pressure.

Temperature

Acid reaction rate increases directly with temperature. At 140 to 150”F, the reaction rate of HCI and limestone is

ACIDIZING 54-5

.INTENSIFIED

5 IO 15 20 25

TIME IN MINUTES

Fig. 54.5-Comparative reaction rates of conventional and intensified acids.

approximately twice that at 80°F. It must be recognized that the temperature controlling the reaction is affected by the injection temperature of the acid (a major factor), and by the heat liberated by the reaction itself (a minor factor). Computerized programs are used to estimate the bottomhole fluid temperature at various stages, allowing more effective acid treatment design.

Flow Velocity Fig. 54.7 shows that increased flow velocity increases the reaction rate of 15 % HCl with CaCO 3. This velocity effect is more pronounced in narrower fractures. Reaction rate is a function of shear rate, 6 v/b, set - ’ as illustrated by the following equation:

R=[(28.5 v/b)0.8+184]x10-6, . . . . . . . . . . . ...(l)

where R is the reaction rate in lbmisq ft-set, v is the flow velocity in fracture, ft/sec, and b is the fracture width, ft. (The reaction rate is for 15% HCl with marble at 80°F under 1,100 psi pressure.)

The flow velocity in fractures and channels depends on injection rate and actual geometry of the flow path.

vd=O. 18i,,l(rfb) (radial fracture), . . .(2a)

vlf= 1,15i,,l(hb) (linear fracture), . . . (2b)

v,, = 17.2i,,/d2 (cylindrical channel). . . . .(2c)

where v = flow velocity in fractures and channels,

ftlsec, 1ac = acid injection rate, bbl/min, rf = fracture radius, ft, h = fracture height, ft, d = channel diameter, in., and b = fracture width, in.

Acid Concentration

Reaction rate increases with acid concentration up to 24 to 25% HCl, but not proportionally, as shown in Fig.

PRESSURE (PSI)

- MARBLE

400 800 1200 1400 2000 2400

Fig. 54.6-Effect of pressure on reaction rate (15% HCI tit 80°F).

I 10 IO0 1,000 10,000 40,000

, ACID FLOW VELOCITY ,s,ce,

FIAClUlE WIDTII

Fig. 54.7-Effect of flow on reaction rate (15% HCI with CaCO,).

54.8. Above 25% HCl, the reaction rate actually decreases because of reduced acid activity. As acid spends, the reaction rate decreases as a result of reduced acid concentration and the retarding effect of dissolved reaction products, such as calcium or magnesium chloride.

Area/Volume Ratio

Area/volume (A/V) ratio is one of the major factors affecting reaction rate spending time, and may vary over a wide range. This ratio, the area in contact with a given volume of acid, is inversely proportional to pore radius or fracture width. Fig. 54.9 shows the time required for 15% HCl to spend on marble, at 80°F and 1,100 psi, for three different A/V ratios.

The term “spending time” has very little meaning or value by itself. It must be related to flow geometry and, thus, to the distance the acid penetrates before it is spent. In matrix acidizing, extremely high A/V ratios may be encountered. For example, a IO-md, 20%-porosity limestone may have an A/V ratio of 28,000 to 1. In such a formation, it would be very difficult to obtain significant penetration before spending. A natural fracture, 0.00 1 in. wide, has an A/V ratio of 3,200: 1. A 0. l-in. fracture has an A/V ratio of 32: 1. The smaller ratios in wider frac-

PETROLEUM ENGINEERING HANDBOOK

I 0 5 IO I5 20 25 30 35

PERCENT HCI

Fig. 54.8-Effect of concentration on reaction rate and spending rate.

TABLE 54.3-EFFECT OF TEMPERATURE ON ORGANIC INHIBITOR PROTECTION

TIME

Protection Concentration Temperature Time

WI C’F) (hours) 0.6 175 24 1.0 250 6 2.0 300 6 2.0’ 350 4

‘With mhtbltor aId

tures allow greater penetration of the acid into the reservoir before spending is complete.

Formation Composition

Probably the most important factor that governs effectiveness of an acidizing treatment is the rock composition. Its chemical and physical characteristics determine how and where the acid will react with and dissolve the rock.

From the standpoint of chemical composition, there is little difference in the reaction rate of HCI on most limestones, all other factors remaining constant. The physical rock texture. however, can control pore size distribution. A/V ratio, pore geometry, and other properties. This, in turn, influences the type of flow channels created by acid reaction and is the key to acid response.

“0 10 20 30 40 50 60 ‘0 Th4E (min)

Fig. 54.9-Effect of A/V ratio on spending time (15% HCI, 80°F and 1,100 psi).

Two formations having the same acid solubility and permeability may respond differently to acid treatment because of variances in physical structure.

Acid Additives The use of a corrosion inhibitor as an additive made possible the first commercially feasible acidizing treatments. Since that time, many auxiliary chemicals have been developed to modify acid solutions, influencing their application and recovery.

Corrosion Inhibitors

Inhibitors are chemical materials that, when dissolved in acid solutions, greatly retard the reaction rate of the acid with metals. They are used in acidizing to avoid damage to casing, tubing, pumps, valves. and other well equipment. Inhibitors cannot completely stop all reaction between the acid and metal; however, they do slow the reaction, eliminating 95 to 98% of the metal loss that would otherwise occur. Most inhibitors have practically no effect on the reaction rate of acid with limestone, dolomite, or acid-soluble scale deposits.

The length of time that an inhibitor is effective depends on the acid temperature, type of acid, acid concentration, type of steel, and the inhibitor concentration.

Organic inhibitors in HCI are effective up to 400”F, but above 200°F relatively large concentrations are required. The effect of temperature on corrosion inhibition is illustrated in Table 54.3.

Equations have been developed for estimating BHT’s during acid treatments. By knowing these temperatures, adequate corrosion protection can be provided, even in wells with static BHT’s up to 400°F.

Surfactants

Surfactants are chemicals used to lower the surface terl- sion or interfacial tension of fresh acid or spent acid solutions. The use of a surfactant improves the treating efficiency in a number of ways.

The presence of a surfactant improves the penetrating ability of the acid solution entering a formation. This is extremely desirable in matrix acidizing treatments. be-

ACIDIZING 54-7

z-ST3;2 lpoo I

0’a 800yORDlNARY A C I D ,0

g 6 0 0i;i

/

Egjpek&k! 0 5 IO 15 2 03z

PENETRATION IN FORMATION- FEET

E

Fig. 54.10—Effect of surface-tension-reducing agent in facili-tating return of spent acid.

cause it provides deeper penetration of acid into the for-mation. In addition, surfactants permit the acid topenetrate oily films clinging to the surface of the rock andlining the pores, so that the acid can come in contact withthe rock and dissolve it.

The use of surfactants also facilitates the return of spentacid following the treatment (Fig. 54.10). Wetting of theformation is more nearly complete and there is lessresistance to flow of the acid, so that the spent acid isreadily returned through the treated section. This is es-pecially important in low-pressure wells.

Another advantage in the use of surfactants in acid isthe demulsifying action obtained. Many surfactants arecapable of inhibiting the occurrence of emulsions or de-stroying those already formed.

Surfactants also promote dispersion and suspension offine solids to provide better cleanup following treatment.These solids may be either mud solids or natural finesreleased from the formation. They are suspended andphysically removed from the formation.

Special surfactants are used as antisludge agents. Somecrudes form an insoluble sludge when in contact with acid.The sludge consists of asphaltenes, resin, paraffin, andother complex hydrocarbons. The acid reacts with thecrude at the interface, forming an insoluble film. Thecoalescence of this film, which results on the sludge par-ticles, can be avoided by use of proper additives. Ethyl-ene glycol monobutyl ether is a mutual solvent surfactantused in matrix sandstone acidizing to water-wet the for-mation. This agent prevents particle migration and sub-sequent particle plugging. It improves cleanup bypreventing the stabilization of emulsions by fine particles.Many different surfactants are used in acidizing. Type andconcentration for a particular application should be select-ed on the basis of laboratory testing.

Silicate-Control AgentsVarious silicate compounds, commonly known as claysand silts, usually are present in most limestones and dolo-

PHI t-942 PH3 PHI PH5

Fig. 54.11—Photograph showing effect of pH on the volume ofsilicate particles.

mites. One of the characteristics of these silicates is thatthey will swell in spent acid. Naturally, this is undesirblebecause swollen silicate particles may block formationflow channels, reducing well production.

Silicate-control additives are chemicals that preventreleased silicate particles from adsorbing water. Somebuffer the pH of the solution near the isoelectric point(where the volume of the swelled clays is at a minimum).Others cause shrinkage of the silicate particles by replac-ing the adsorbed water molecules with a water-repellentorganic film. Thus, possible formation plugging isprevented, treating pressures are lowered, faster cleanupis provided, and the occurrence of particle-stabilized emul-sions is minimized. This is illustrated in Fig. 54.11.

Iron-Control AgentsIron control is approached two ways. The oldest and mostcommon approach is to use sequestering agents, whichact by complexing iron ions, thereby preventing precipi-tation when the acid spends. A second method is use ofreducing agents that reduce any ferric ions (Fe3+) to fer-rous ions (Fe2+), which do not precipitate as the hydrox-ide or hydrous oxide until the pH of the system is above7. Since acids in contact with the formation rock will notspend to a pH that high, the hydroxide will not damagethe well. Spent acid usually has a pH between 4.5 and6.5, no higher.

Erythorbic acid is one of the most effective reducingagents that can be used for this purpose. The reductionof all the ferric iron to ferrous iron, however, does notprevent the precipitation of ferrous sulfide (FeS), whichprecipitates when the acid spends to a pH of 2, as it willreadily in almost any formation. To protect fully againstiron precipitation in a sour well, a complexing agent isneeded. Citric, lactic, and acetic acids as well as EDTAor NTA are popular sequestrants. In some wells whereH2S can become mixed with the acid it also may be ad-visable to use both the reducing agent and the sequester-ing agents, since ferric iron can react with H2S to


precipitate free sulfur, which itself can damage permeability The loss of effectiveness of acetic acid at temperatures above 125°F and the possibility of precipitating calcium citrate also are factors that should be considered in guarding against iron precipitates.

Alcohols

Methyl and isopropyl alcohols sometimes are used at concentrations of 5 to 20 ~01% of acid to reduce surface tension. Methyl alcohol is sometimes used at concentrations, up to 66 % to increase vapor pressure of the acid and spent acid solution. Use of alcohols thus improves both rate and degree of cleanup, which can be particularly helpful in dry gas wells.

Gelling and Fluid Loss Agents

Natural gums and synthetic polymers are added to acid to increase the viscosity of the acid solution. 3 This reduces leakoff into large pore spaces and, to some extent, into natural hairline fractures. It also provides some degree of reaction rate retardation.

Other materials used to control leakoff are fine (IOO- mesh) sand4 and fine salt.5 These materials bridge in hairline fractures to reduce fluid flow out of the main fracture during fracture acidizing treatments.

Another successful fluid-loss control agent is a mixture of finely ground, oil-soluble resins. 6 Originally designed as a diverting agent for use through gravel packs during sandstone matrix acidizing treatments, this agent was later shown to be effective as a fluid-loss agent in fracture acidizing, when used at higher concentrations. ’

Liquefied Gases

Liquid nitrogen and liquid CO2 sometimes are used in acid solutions to provide added energy for better well cleanup. Nitrogen also is used to make foamed acid, which provides excellent leakoff control in low permeability rock. 8.9

Retarded Acids

It is often desirable in acid fracturing treatments to retard the reaction rate of the acid to provide deeper penetration of active acid into the formation. Retardation may be accomplished by use of slower-reacting acids (HAc and HCOOH), by adding chemicals to reduce reaction rate, or by increasing concentration to extend spending time.

HAc and HCOOH are weakly ionized and sometimes are used to obtain longer reaction time. The additional cost of these acids may prohibit extensive use in certain formations. Deeper matrix penetration than would be obtained by HAc or HCOOH is obtained by the faster- reacting HCl because the channeling or wormhole effect produced by the HCl reduces the A/V ratio, thus prolong- ing reaction time. In fractures, the HAc and HCOOH would obtain deeper penetration than HCl; however, larger volumes would be required to dissolve an equivalent amount of rock.

Some chemicals, added to HCl, form a barrier on the rock surface, which interferes with its normal contact and “retards” the reaction rate of the acid. Acid-in-oil emulsions generally exhibit retarded reaction rates. The acid in the emulsion does not completely contact the rock sur-

face because of the presence of an interfering oil film. This is particularly true for emulsions with at least 20% oil as the outer phase. Certain surfactants recently have been found to be beneficial in reducing reaction rate and, thus, extending spending time and penetration distance. These surfactants, in the presence of oil, provide a hydrophobic or water-repellent, oil-like film on the rock surface that restricts acid/rock contact. Fluid-loss materials and gelling agents (acid-thickening additives) also tend to reduce the reaction of HCl by film development on rocks.

High concentrations of an acid provide longer reaction times than lower concentrations because (1) there is more acid to react, (2) the additional reaction products further retard reaction rates, and (3) the enlarged flow path, with reduced A/V ratio, extends the spending time and penetration of a high-concentration acid. For example, 28% HCl may take four to six times longer to react completely than does 15% HCl. In this case, the reaction time is extended in spite of the initially faster reaction rate of the 28% HCl.

Acidizing Techniques There are three fundamental techniques used in acidizing treatments.

1. We&ore Cleunup. This entails fill-up and soak of acid in the wellbore. Fluid movement is at a minimum, unless some mechanical means of agitation is used.

2. Matrix Acidiz,ing. This is done by injecting acid into the matrix pore structure of the formation, below the hydraulic fracturing pressure. Flow pattern is essentially through the natural permeability structure.

3. Acid Fmcturing. This is injection into the formation above hydraulic fracturing pressure. Flow pattern is essentially through hydraulic fractures: however, much of the fluid does leak off into the matrix along the fracture faces.

The technique selected will depend on what the opera- tor wishes to accomplish with the treatment.

Matrix acidizing may be selected as a proper technique for one or more of the following reasons: (1) to remove either natural or induced formation damage, (2) to achieve low-pressure breakdown of the formation before fracturing, (3) to achieve uniform breakdown of all perforations, (4) to leave zone barriers intact, or (5) to achieve reduced treating costs.

The principal types of formation damage are mud invasion, cement, precipitates, saturation changes, and migration of fines. The effect of damage on injectivity or productivity is shown in Figs. 54.12 and 54.13. It can be seen that the greatest flow increase results from restor- ing the natural rock permeability. The magnitude of this primary flow increase depends on the extent (radius) of the damage. Further increase in pore size by matrix acidizing results in only a limited increase in flow (stimulation).

If the producing formation does not have enough natural permeability, then a hydraulic fracturing treatment should be considered. The primary purpose of fracturing is to achieve injectivity or productivity beyond the natural reservoir capability. An effective fracture may create a new permeability path, interconnect existing permeability streaks, or break into an untapped portion of the reservoir.

ACIDIZING 54-9

5

00

m

0 I 2 3 4 6 7 0 9 lo

RADIAL EXTENTd c4ALGul ZorE. FEET

Fig. 54.12-Effect of damaged zone on flow.

The success of any fracturing treatment depends on two factors: fracture conductivity and effective penetration, as illustrated in Fig. 54.14. If enough etched fracture conductivity can be achieved, then increased penetration be- comes important. For any given formation, there will be an optimum conductivity and penetration, which will be controlled by cost. In other words, there will be some point where production increase per dollar spent will be a maximum. This must be determined by pretreatment design.

Laboratory Testing The physical and chemical characteristics of the formation rock often affect the results of an acidizing treatment. In some cases, the use of special additive chemicals will improve the action of the acid or avoid cleanup difficul- ties in returning the spent acid following the job. It is important, therefore, that samples of the formation rock (either cores or cuttings) and, if possible, samples of the crude oil and formation brine be subjected to laboratory testing before acidizing to design the most effective treatment.

Customarily, permeability. porosity, and oil- and water- saturation tests are run on formation core samples, using standardized core-analysis procedures. In addition, acid- solubility tests are run to determine to what extent the formation will respond to an acidizing treatment.

Formation solubility may be determined two different ways. In the first method, a weighed chunk of the rock is immersed in an excess of acid and maintained at formation temperature. After an hour, any insoluble residue is washed. dried, and weighed. With samples known to contain silicates, additional tests may be run in which the rock is exposed to the dissolving action of combined HCl and HF.

A more rapid test, suitable for samples known to con- sist largely of limestone or dolomite, entails dissolving a weighed sample of the rock in an excess of HCl and measuring the volume of CO* gas evolved during the reaction. A simple apparatus for conducting this test is shown in Fig. 54.15.

In addition to these tests of the formation rock, the emul- sifying tendencies of the formation crude should be determined whenever possible. Samples of the crude are mixed

25

I IO 100 1000

PERCENT OF NATURAL PERMEAElllTY

Fig. 54.13-Effect of permeability changes on radial flow.

McGUlRE AND SIKORA

IO' IO' IO' ID' IO'

RELATIVE CONDUCTIVITY, bk#,,-In

Fig. 54.14-Relationship of conductivity and penetration to productivity increase. J= productivity index of well after stimulation, J, = productivity index before stimulation, ri = radius of fracture (ft), re = drainage radius (ft). k,=permeability of fracture (md), k, = permeability of formation (md), and b = fracture width (in.).

with the acid to be used in the acidizing treatment and then are shaken. The mixture is allowed to stand, and the time required for the oil and acid to separate is observed. Additional tests are run on mixtures of the crude oil with acid that has been spent completely on pulverized formation rock. If the formation crude shows a tendency to emulsify with either the fresh acid or the spent acid, the use of an appropriate surfactant is indicated.

Similar tests using a mixture of crude and acid are made to determine acid sludging tendencies. Sludge is identi- fied by filtering the mixture through a small mesh screen. Appropriate surfactants that are added to the acid to prevent sludge formation are evaluated.

Other determinations of rock characteristics include tests for clay swelling tendencies and tests to determine rock composition (such as X-ray diffraction analysis) to indicate need for stabilizers, sequestering agents, or other acid additives.


Fig. 54.15-Laboratory solubillty tester (carbon dioxide evolu- tion method).

Acid Treatment Design Three techniques of acidizing have been described previously. Wellbore cleanup treatments normally do not re- quire complicated design procedures. Matrix and fracture acldlzmg treatments. on the other hand, can involve extensive predesign laboratory testing and complicated design procedures and calculations.

Matrix Acidizing-Carbonate Formations

Matrix acidizing in carbonates normally is used to break down all perforations and to remove damage. Plugging materials can be removed and permeability restored in two ways: (1) by dissolving the damaging material itself or (2) by dissolving part of the rock in which the damage exists. In carbonate rocks with acid solubilities greater than 50%) the latter method is often most effective. The dislodged solid particles or liquids then can bc removed physically by the return of the spent acids to the well.

HCI normally is used in matrix treatments of carbonates, but HAc and/or HCOOH should be considered

TABLE 54.4-FLOW THROUGH PORES OF VARIOUS SIZES

Diameter of Pore Pore Volume Flow Through Pores (A w (% of Total Flow) il 60 10

1 to 2 25 15 2 to 5 12 30

5 and above 3 45

for wells with temperatures in excess of 250 to 300°F. Any acid solution should be modified by use of proper additives to meet special situations.

Acid inhibitor selection must be based primarily on treating temperature and, to some extent, on the type of acid formulation.

Surfactant type and concentration should be selected to minimize emulsion tendencies and, perhaps, to aid in dis- persing fine undissolved solids. These may be drilling mud, cement solids, or natural clay particles released from the formation. Suspension and removal of these materials can play an important part in the overall treatment results.

Diverting agents may be used to promote uniform penetration in long sections. Acid-swellable synthetic polymers, controlled-solubility particulate solids, perfo- ration ball sealers, gel slugs, etc., have been used suc- cessfully to provide more uniform injectivity. Assuring the distribution of acid into the entire interval is a critical part of carrying out a matrix treatment. Otherwise, large portions of the interval may get very little, if any, acid.

In matrix acidizing, injection rates should be controlled so that the formation is not fractured. The use of as high a rate as possible without exceeding the fracturing pressure is recommended. In certain cases, it may be necessary to create a fracture to open perforations, after which pressure can be reduced below fracturing pressure, thus providing a matrix flow pattern.

Controlling the injection pressure is the primary con- cern. Maintaining bottomhole pressures below hydraulic fracturing pressures may restrict injection rates to only fractional barrels per minute. An increasing rate may then be possible as the treatment progresses.

Because of differences in the size and shape of the pores, penetration of acid in a carbonate rock is far from uniform. Porosity anomalies may result from vugs, hairline fissures, or tortuous capillary-like pores. Because of these heterogeneities, a “channeling” or “wormholing” occurs with most acid formulations. The resultant effect is the attainment of much greater acid penetration of matrix than expected.

The wide distribution of flow in a rock of varying pore diameters (Table 54.4) is further accentuated by acidizing. As discussed in a preceding section, the fast-reacting HCl may provide greater penetration of the limestone matrix than the slow-reacting acetic acid, but not as great as with the emulsified or gelled acids. Evidently, the slow reaction of acetic acid does not change the flow distribution rapidly enough to “channel,” but rather results in several small pore enlargements for short distances as op- posed to a few large, long channels.

Since the formation damage normally does not exist for a great distance from the wellbore, the volume of acid needed is small. With a formation porosity of IO%, 60

ACIDIZING 54-11

gal of acid per foot of section will fill the porosity to a radius of 5 ft. Usually, matrix treatment volumes range from 50 to 250 gal per foot of section. If damage is deeper than 5 to 10 ft, then larger volumes of acid, a means of retarding the reaction rate, or, perhaps, fracturing techniques, may be required. Very little rock must be dissolved to result in a significant amount of damage repair or permeability increase. Removal of only 1% of limestone or dolomite rock for a distance of about 5 ft from the wellbore requires only 70 gal of 15 % HClift of verti- cal interval.

An overflush in the matrix acidizing treatment is recommended. This will ensure efficient displacement of the acid into the matrix. A minimum shut-in time is recommended before returning the spent acid to the well. Since the spending time of acid is short, a long shut-in time of several hours is not necessary, even for the so-called ‘ ‘retarded acid. ’ ’ The overflush fluid may be brine, water, oil, or a weak acid. Enough volume should be used to ensure maximum penetration of the last portion of the acid, before it is spent.

Matrix Acidizing--Sandstone Formations

The purpose of sandstone acidizing is to restore permeability by dissolving away formation-damaging clay-like minerals or other acid-soluble materials. The clay may be inherent in the formation or may be the result of drilling mud or workover fluid invasion.

The type of acid used most often in sandstones is a mixture of HF and HCl. These mixtures commonly are rem ferred to as mud acids or mud removal acids. As previously discussed, fluoboric acid also has become popular in sandstone formations. Concentrations of 2 to 6 % HF and 8 to 12 % HCl normally are used. If a significant amount of calcium carbonate is present in the formation (5 to lo%), a spearhead of HCl should be used to react with it before the HF/HCl is injected. With carbonate content above 20%, HF acid probably is not needed, except to give entry through clay damage.

As in any matrix-type treatment, injection of the HF/HCl should he below fracturing pressure. The volume of acid required depends on the depth and severity of the damage. A total of 50 to 250 gal of acid per foot of interval is the normal treatment volume, if damage is not extensive. An acid solubility test may not be a realistic evaluation of acid requirements.

Results of a field study by Gidley et al. lo confirmed some earlier recommendations based on laboratory core flow studies. These results showed much greater success when more than 125 gal/t? acid was used.

The reported core flow test showed what response the formation will have to acid. This is illustrated in Fig. 54.16. Although some of these formations have approximately the same acid (HF/HCI) solubility, permeability, and porosity, the response to acid is quite different.

Initial reduction in permeability is a common occurrence observed with many formation core flow tests. It is at- tributed to sloughing particles (clays, silica, fines, etc.) that apparently bridge in the flow channels and restrict flow, before their further reaction with the acid. An in- adequate acid volume treatment could lead to a restricted permeability in a formation, if the bridging is severe.

Since secondary reactions may occur, resulting in possible precipitation of damaging reaction products, mud

"0 5 IO 15 20 MUD ACID VOLUMf RfPUIRfMENT5 (p.l/f12)

Fig. 54.16--Response of cores from producing formations to mud acid.

acid should be returned to the wellbore as soon as the initial spending time has elapsed. The spent HF/HCl acids should not be allowed to mix with formation brine, if at all possible because of the danger of precipitates.

Inhibitors, surfactants, and diverting methods should be selected just as in an HCl acid treatment. As in the case of matrix acid treatment in carbonates, an overflush is recommended. Suitable fluids include weak acid, oil, or water. Formation brine should not be used to overflush HF/HCl. Short shut-in times should be used-a few hours at the most.

Fracture Acidizing-Carbonate Formations

The primary purpose of an acid fracturing treatment of a carbonate formation is to achieve productivity or injectivity beyond the natural capabilities of the reservoir. It is most applicable in formations with a low and/or ineffec- tive permeability structure. The effectiveness of an induced hydraulic fracture is a function of both its conductivity and the extent of penetration of the drainage radius of the well.

These factors will depend on well and reservoir properties, formation characteristics, injection rate, type and volume of acid used, and shape and orientation of the fracture. All these factors have been correlated by several companies into “guides” to acid fracture treatment design. Such guides provide mathematical relationships for determining the fracture area and conductivity achieved by different volumes of specific acid formulations at various injection formulations. These guides are programmed for computer calculation, so that rapid comparison of various treatment designs can be made for selection of best results per dollar of treatment cost. These guides are not sufficiently similar to get clear comparison between different companies but should be compared only with other calculations from the same system.

Critical Wells In ultradeep, high-temperature wells, many factors must be considered in the stimulation treatment design. First, the high BHT can drastically affect reaction rate of acid, inhibition, and other properties of the acid formulation.


These effects can be partially offset by formation cool- down techniques. Basically, this consists of pumping a pad volume of fluid (generally gelled water) into the formation to cool the rock to a more normal treating temperature. Most companies have computer programs available to calculate pad volumes required for a given temperature reduction.

Another problem is created when fluids with temperatures lower than BHT’s are used. This problem is mechanical and involves tubing movement. In ultradeep wells, such contraction can create stress in the tubing greater than tubing strength, resulting in a parted string. The solution to this problem is to slack off or to release tension at the top of the tubing string as the job progresses. Again, computer programs are available from most service companies to predict tubing movement under given conditions.

Summary In summary, acidizing is a process that uses reactive materials to increase well production by dissolving either the reservoir rock or damaging materials blocking the pore spaces of the rock. Different kinds of acids and additives are available, so that treating fluids can be tailored to meet individual well needs. Acid formulations may be applied in either matrix- or fracture-type treatment, depending on the degree of stimulation or production increase desired. While acidizing, and acidizing treatment design, in detail are beyond the scope of this text, published literature offers answers and assistance in solving many of the problems encountered. The General References cover many of the recent technical developments in this field. In addition, most service companies providing acidizing service offer laboratory facilities, technical assistance, and computer programs for problem analyses and treatment design.

References I.

2.

3.

4.

5.

6.

7.

8.

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ACIDIZING 54-13

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Shaughneasy, C.M. and Kunze. K.R.: “Understandmg Sandstone Acidizing Leads to Improved Field Practices.” paper SPE 9388 presented at the 1980 SPE Annual Technical Conterence and Exhibttion, Dallas. Sept. 2 l-24.

Smith, C.F., Dollarhide. F.E.. and Byth, N.J.: “Acid Corrosion Inhibitors-Are We Getting What We Need?” J. Pet. Tech. (May 1978) 737-46.

Smith, C.F., Crowe. C.W.. and Wieland. D.R.: “Fracture Acidizing in High Temperature Limestone.” paper SPE 3008 presented at the 1970 SPE Annual Meeting, Houston. Oct. 4-7.

Smith, C.F., Crowe, C.W., and Nolan, T.J. III: “Secondary Deposition of Iron Compounds Following Acid Treatments,” J. Pet. Tech. (Sept. 1969) 1121-29.

Smith. C.F., Nolan, T.J. III, and Crenshaw, P-L.: “Removal and Inhibition of Calcium Sulfate Scale In Waterflood Projects.” J. Per. Tech. (Nov. 1968) 1249-57.

Smith, C.F., Ross, W.M., and Hendrickson, A.R.: “Hydrofluoric Acid Sttmulation-Developments for Field Application,” paper SPE 1284 presented at the 1965 SPE Annual Meeting. Denver. Oct. 3-6.

Smith, C.F. and Hendrickson. A.R.: “Hydrofluoric Acid Stimulation of Sandstone Reservoirs.” J. Per. Tech. (Feb. 1965)215-22; Trum.. AIME, 234.

Swanson, B.L.: “Well Acidizing Composntons,” U.S. Patent No. 4,240,505 (1980).

Vivian. T.A.: “Acidification of Subterranean Formations Employing Halogenated Hydrocarbons,” U.S. Patent No. 4,320.014 (1982).

Wade, R.P. and Aziz, K.: “Stimulating the Triassic Carbonates in the Foothills Gas Trend of Northeast Brittsh Columbia,” paper 81-32-35 presented at the 1981 CIM Annual Meeting, Calgary.‘May 5-6

Walsh. M.P., Lake. L.W., and Schechter. R.S.: “A Deacriptton of Chemical Precipitation Mechanisms and Their Role in Formation Damage During Stimulation by Hydrofluoric Acid.” fro<. SPE For- mation Damage Control Sympostum, Lafayette. LA (1982) 7-27.

Watkins, D.R. and Roberts, G.I.: “On-Site Acidizing Fluid Analysis Shows HCI and HF Contents Often Varied Substantiallv From Speci- fied Amounts,” paper SPE 10770 presented at the 1982 SPE California Regional Meeting, San Francisco, March 24-26.

Wiley, C.B.: “Success of a High Friction Diverting Gel in Acid Sttmulation of a Carbonate Reservoir, Cornell Unit, Wasson San Andres Field,” .I. Pet. Tech. (Nov. 1981) 2196-2200: Trans.. AIME, 271.

Woodroof, R.A. Jr., Baker, J.R., and Jenkins, R.A. Jr.: “Corrosion Inhibition of Hydrochloric-Hydrofluoric Acid/Mutual Solvent Mixtures at Elevated Temperatures,” paper SPE 5645 presented at the 1975 SPE Annual Technical Conference and Exhibition, Dallas. Sept. 29-Oct. 1.

Young, P.J. and Romocki, J.M.E.: “Well Treating Compositions and Method,” Great Britain Patent No. 2.047,305 (1980).

Acidizing

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