Fluid-Loss Control: The Key to Successful Acid Fracturing c.w. Crowe, SPE, B.H. Hutchinson, * and B.L. Trlttipo, Dowell Schlumberger

Summary. Acid fluid loss is extremely difficult to control and is generally considered to be the major factor limiting the effectiveness of acid fracturing treatments. Chemical erosion of fracture faces and the development of wormholes are largely responsible for the re­duced efficiency of acid fracturing fluids. The creation of acid wormholes increases the effective area from which leakoff occurs, thus reducing the acid hydraulic efficiency. Once wormholes form, most acid fluid loss originates from these wormholes rather than penetrat­ing uniformly into the fracture face.

Methods of acid fluid-loss control are discussed and evaluated with an improved fluid-loss test procedure. This procedure uses lime­stone cores of sufficient length to contain wormhole growth. Studies demonstrate that if wormhole growth can be controlled, acid fluid loss approaches that of nonreactive fluids.

An improved acid fracturing fluid having unique rheological characteristics is described. This acid has a low initial viscosity but tempo­rarily becomes extremely viscous during leakoff. This high leakoff viscosity blocks wormhole development and prevents acid entry into natural fractures. After the treatment, spent-acid viscosity declines rapidly to ensure easier cleanup.

Introduction Acid fracturing is a well stimulation process in which acid, usually HCl, is injected into a carbonate formation at pressures sufficient to fracture the formation or to open existing natural fractures. As acid flows along the fracture, portions of the fracture face are dis­solved. Because flowing acid tends to erode fracture faces nonuni­formly, conductive channels, which usually remain after fracture closure, are created. The effective fracture length is determined by the volume of acid used, its reaction rate, and the acid fluid­loss rate. Productivity improvement is largely a function of the length of the etched fracture.

The maximum effective distance obtainable by acid fracturing is limited by either spending or fluid loss. If the acid spends too rapidly, the etched portion of the fracture will be rather short. If acid fluid-loss characteristics are poor, excessive leakoff will ter­minate fracture growth. It is commonly believed that, at low to moderate temperatures, acid leakoff is the dominant factor limit­ing the effective length of the etched fracture. l

During many, if not most, acid fracturing treatments, the treat­ing pressure declines continually, eventually falling below a level required to propagate the fracture. Thus, fracture extension becomes impossible. In some cases, treating pressure never reaches a level sufficient to initiate a hydraulic fracture, indicating that the acid is expended in a matrix treatment of the near-well bore region. For maximum stimulation results, the treating pressure must remain above fracturing pressure during the entire treatment. Acid pumped below this pressure cannot contribute to fracture extension.

Fluid-loss control during acid fracturing of carbonate formations presents problems unique to reactive fluids. Most fluid-loss addi­tives and gelling agents used in nonreactive aqueous fracturing fluids are unstable in acid. As a result, special acid-stable additives must be used. In addition, acid flow along carbonate fracture surfaces produces constant chemical erosion, thus making it difficult for wall­building fluids to deposit an effective filter cake. Another compli­cation is that during leakoff, acid tends to enlarge certain larger pores and natural fractures selectively, resulting in wormholes and channels perpendicular to the fracture face. This phenomenon great­ly increases the effective surface area from which leakoff occurs and is generally believed to affect acid fluid loss adversely. 2

Various additives and treating techniques have been developed as means of controlling acid fluid loss. One of the earliest acid fluid­loss additives was karaya gum. Unlike most natural gums, karaya gum does not readily dissolve in acid but forms small swollen par­ticles that act to block wormholes physically in the early stages of their development. The effectiveness of karaya gum is limited, how­ever, by its rapid acid hydrolysis at temperatures above 125°F [52°C]. To overcome this problem, synthetic acid-swellable poly­mers were later developed. Although these materials performed well in laboratory tests, field treatments produced mixed results. In ad-

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Copyright 1989 Society of Petroleum Engineers

SPE Production Engineering, August 1989

dition to suffering from mixing and gravity-separation problems, the increased polymer stability occasionally resulted in poor or in­complete posttreatment cleanup.

To be effective, additives must be stable in acid at elevated tem­perature. Fluid-loss additives that are stable in hot acid, however, are generally very difficult to dissolve or to degrade after the treat­ment. One method of overcoming this problem involves the use of an oil-soluble acid fluid-loss additive. Additives of this type are usually composed of a mixture of oil-soluble resins. This resin mix­ture consists of rigid larger-size material, which acts to bridge large pores in the formation, and a smaller-sj}:e pliable resin, which serves as a filtration-control agent by deforming and sealing the spaces between the larger particles. Nierode and Kruk 1 evaluated the per­formance of various acid fluid-loss additives against long limestone cores and found an oil-soluble resin mixture to be the only product capable of controlling acid fluid loss at differential pressures simulat­ing those encountered downhole. The major limitation of this sys­tem is the high concentration of additive required for fluid-loss control. At the required concentration of 200 lbmll ,000 gal [24 kg/m3], high additive costs have limited the commercial applica­tion of this product.

Acid fluid-loss additives generally are not often used because of performance and cost limitations. As a result, alternative methods of fluid-loss control are sometimes incorporated. The most com­mon technique involves injection of a viscous, nonreactive pad preceding the acid. 3 This technique usually includes a water-based fracturing fluid to cool the fracture and to lay down an impermea­ble filter cake on the fracture face. While the technique is widely used, studies l .4 have shown that such filter cakes are relatively in­effective for acid fluid-loss control. Laboratory tests reveal that the filter cake is quickly penetrated by wormholes resulting from even small amounts of acid leakoff. Once this occurs, acid fluid loss is identical to that observed if no pad were used.

While the use of the pad probably provides only limited acid fluid­loss control, it does have other useful functions. It cools the tubu­lar goods through which the acid must flow, thus reducing corro­sion. It also cools the fracture and increases fracture width, resulting in reduced acid reaction rate and increased live-acid penetration. As an added benefit, the viscous pad promotes acid fingering, thus reducing the amount of reactive surface area to which the acid is exposed and improving fracture length and conductivity. 5

Recognizing the limitations of a single stage of pad for control­ling acid fluid loss, researchers developed variations of this tech­nique. In one such procedure, the fracture is initially created by a gelled pad, after which alternating stages of acid and additional pad are pumped. 4 These additional pad stages are designed to enter and seal wormholes created by the preceding acid. Alternating acid and gel stages allows acid leakoff into wormholes and enlarged natural fractures to be controlled and treatment efficiency to be im­proved. Fine particulate material is often added to the pad stages to aid in fluid-loss control. 4 Various particulate materials are used

215

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PUMP

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OISPLACEIoI£NT CI;<M."

L

Fig. 1-Laboratory core-flow equipment used in acid fluid-loss studies.

for this purpose, the most common of which is lOO-mesh sand. Oil­soluble resins and salt of a similar particle size are also sometimes used. 6

Acid fluid loss can also be reduced by gelling the acid. This method of fluid-loss control has become widely used since the de­velopment of more acid-stable thickening agents. 7 Thickeners most commonly used include xanthan biopolymers, various acrylamide copolymers, and certain surfactants that thicken acid by micellar association. The effectiveness of gelling agents for controlling acid fluid loss varies greatly, depending on the gelling agent used and well conditions encountered.

Nature of Acid Fluid Loss A full understanding of the 'nature of acid fluid loss is important in developing effective methods for controlling it. That acid leakoff into permeable carbonate rock results in the creation of wormholes has long been known. This phenomenon has been the subject of numerous investigations. These studies2,8,9 show that a few large pores initially receive a disproportionate amount of acid, resulting in their rapid selective enlargement. Consequently, most of the acid enters a few enlarged pores, creating the observed wormhole ef­fect. The creation and branching of wormholes and enlargement of natural fractures have a major effect on acid fluid loss because

216

30

o

/. /.

TEMP 150"F

~.-.--.-.-

-- 0.1 ml/min --_. 0.25 ml/min •••••• 0.5 ml/mln ·-1 ml/min

G:· .. ·· ............ ··· .... ·············· .. ·················

----------------------------­" " "

o 10 20 30 40 50 60 70

VOL 157. Hel (ml)

Fig. 2-Effect of acid leakoff rate on wormhole growth.

they increase the effective amount of surface area from which acid fluid loss occurs. Factors governing the propagation of these worm­holes are analogous to those affecting acid spending in a hydraulic fracture. Wormholes continue to grow in length, provided that live acid is delivered to the wormhole tip. Thus, increased temperature decreases wormhole penetration distance. Likewise, wormhole depth is lengthened by increased acid concentration and injection rate. Once wormholes reach this maximum spending-limited depth, injection of additional acid acts mainly to enlarge the diameter of existing wormholes. This can be demonstrated by acid core-flow studies performed with the test equipment shown in Fig. I. In these tests, HCl was injected, against a 1,0oo-psi [6.89-MPa] backpres­sure, into permeable Indiana limestone cores measuring 1 in. [2.54 cm] in diameter by 11.8 in. [30 cm] in length. All cores used in this study were cut perpendicular to the bedding plane from the same block of Indiana limestone to minimize permeability varia­tions between cores. In each test, a specified amount of acid was injected into each limestone core, after which the core was cut into O.4-in. [I-cm] segments. Examining the segments and measuring their permeability established the maximum wormhole depth. Fig. 2, a plot of these data, demonstrates the influence of acid injection rate on wormhole penetration distance. At the higher injection rates, deeply penetrating wormholes develop, while wormhole develop-

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Fig. 3-Effect of temperature on wormhole growth.

SPE Production Engineering, August 1989

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20

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0 0 10 20 30 .0 50 60 70

VOLUME Hel (ml)

Fig. 4-Effect of acid concentration on wormhole growth.

ment at lower rates is almost nonexistent. Also apparent is the rapid wormhole growth in length during the early stages of acid injec­tion owing to selective channeling of the acid. For example, at an injection rate of 1.0 mLimin, wormhole penetration reaches a depth of 3.7 in . [9.4 cm] after injection of only 2.5 mL of acid . Note that this penetration depth does not usually represent a single worm­hole but a branched wormhole network. Thus, leakoff of only a small amount of acid greatly increases the amount of new surface area from which fluid loss can occur. This is a major reason why acid fluid loss is more difficult to control than that for nonreactive fluids.

Factors other than leakoff velocity also influence wormhole penetration depth. Fig. 3 illustrates wormhole growth during acid core-flow tests performed at different temperatures. As might be expected, increasing the test temperature decreases the depth of acid penetration.

As shown in Fig. 4, acid concentration also has an effect on worm­hole penetration depth. Increasing HCl concentration from 15 to 28% approximately doubles the effective penetration depth.

The development of wormholes during acid fracturing treatments has several other implications. In addition to increasing acid fluid loss, these wormholes also alter the pattern of fluid invasion into the fracture face. Once developed, acid fluid loss originates predominantly from existing wormholes, with little fluid leakoff actually occurring at the fracture face. This effect is illustrated in Fig . 5. To simulate an existing wormhole, a 0.125-in. [0.32-cm] -diameter hole was first drilled to a depth of 2.6 in. [6.6 cm] into an Indiana limestone core. The core was then mounted in the core­flow apparatus shown in Fig. I . Dyed water was injected; then the core was removed and cut lengthwise to reveal the colored-fluid­invasion pattern. As shown, almost all fluid loss originates from the drilled hole, with little dyed-fluid invasion at the core face. A somewhat similar fluid-invasion pattern is observed when dyed 15 % HCl is injected into a limestone core containing no pre-existing hole. As Fig. 6 shows, almost all fluid loss again originates from the wormhole created by the acid. This observation has several im­portant implications. First, it shows why filter cakes deposited by nonreactive pad fluids have little influence on subsequent acid fluid loss. Once wormholes penetrate a filter cake, they are responsible for almost all acid fluid loss, regardless of any remaining fIlter cake. Second, the acid reaction rate can be retarded by the addition of fIlterable solids to the acid. 10 If tests are performed at a differen­tial pressure low enough to limit wormhole development, such ad­ditives deposit fIlter cakes, which act as barriers between the acid and the fracture surface. While this method of acid retardation is effective under conditions of little or no wormhole development, the existence of deeply penetrating wormholes eliminates most leakoff at the fracture face and prevents fIlter cakes from developing.

The existence of wormholes also influences development of frac­ture conductivity. Because acid fracturing depends on the etching of fracture faces to create flow channels, acid lost to wormholes

SPE Production Engineering, August 1989

Fig. 5-Fluid-lnvaslon pattern as Influenced by a simulated wormhole.

would result in less rock dissolution from the fracture face and thus lower conductivity. Previous studies II showed that localized ~hanges in the permeability of the fracture face have a far smaller effect on productivity than does fracture length or conductivity.

Acid Fluid-Loss Tests The initial problem encountered in any investigation of acid fluid­loss control involves the selection of laboratory test methods. Earlier studies l ,3.4,10 used a variety oftesting techniques, with no partic­ular method being universally accepted. Wormhole development severely complicates acid fluid-loss testing because even moderate amounts of acid leakoff produce channels completely through short limestone cores. Various testing techniques have previously been used to overcome this problem. In some cases, filter paper or sand­stone cores, rather than limestone, were used. This technique pre­vents wormhole development but is not representative of actual treating conditions. Another technique is simply to measure the time required for the wormhole to penetrate a limestone core under a prescribed set of test conditions. While this may provide a com­parison of relative fluid-loss efficiency, it usually does not provide actual fluid-loss volumes. Also, such tests are sensitive to test con­ditions and are actually a measure of wormhole growth rather than fluid loss. Another approach involves tests performed against lime­stone but at very low (5- to 30-psi [34.5- to 206.9-kPa]) differen­tial pressures. This limits acid leakoff to a low level, thus preventing wormhole development, as demonstrated by the data in Fig. 2. While such tests allow measurement of actual acid fluid loss, their value is questionable because differential pressures used are prob­ably far below those actually experienced during actual treatments.

Previous acid fluid-loss studies used differential pressures rang­ing from 5 (Ref. 10) to 1,700 psi (Ref. 1) [34.5 to 11 722 kPa] . The proper choice of realistic test conditions is not readily appar­ent. This choice is very difficult because the actual effective dif­ferential pressure during acid fracturing treatments probably varies greatly, depending on well conditions. To be widely effective, how­ever, any method of acid fluid-loss control should function over a wide range of differential pressures.

These assumptions indicate that the most representative acid fluid­loss test is one that uses rather long limestone cores and is per­formed at differential pressures sufficient to achieve appreciable leakoff with significant wormhole development. Test conditions, however, should not allow acid channeling completely through the core during a normal 25-minute fluid-loss test. All tests should be performed against a backpressure of at least 1,000 psi [6.89 MPa] to minimize gas blockage reSUlting from CO2 generated by acid spending.

Therefore, an acid fluid-loss test was developed with the core­flow apparatus shown in Fig. I. Indiana limestone cores measuring I x 11.8 in. [2.54 x 30 cm] were used in all tests. Test conditions were chosen in which both wormhole growth and spent-acid reac-

217

Fig. 6- Fluld leakoff from wormholes as Illustrated by InJec­tion of dyed 15% HCI (150° F).

tion products would be contained within the core during the test period. At the beginning of each test , 2 % KCl brine was flowed through the core to establish the differential pressure required to achieve a preselected initialleakoff velocity , usually either 0 .5 or 1.0 mLimin. This step established the differential pressure to be used in the fluid-loss test. Use of this procedure served to normal­ize permeability differences of cores used in the tests. After this pressure determination, the acid solution was circulated across the core face, with no differential pressure applied through the core, to flush brine from the system. The acid reservoir was then pres­surized to a level sufficient to achieve the desired differential pres­sure, and the reservoir valve was opened to apply the predetermined differential pressure across the core, thus beginning the test. A con­stant differential pressure was maintained during the test. Acid leakoff was measured by computer monitoring of the fluid volume displaced by the liquid chromatography pump used to pressurize the acid. This procedure was chosen because it provided an actual measurement of acid entering the core. Previous studies 12 showed that HCl spending normally produces more CO2 than can be dis­solved by the spent acid, titus resulting in a gaseous phase of CO2,

As a result, the fluid volume displaced from a saturated limestone core during acid injection is greater than that injected. The direct measurement of acid injected eliminates this problem.

Because acid is not circulated across the face of the core during the fluid-loss test, the test is static rather than dynamic. With nor­mal filter-cake-forming fluids, one might expect dynamic flow to affect fluid-loss results significantly owing to filter-cake erosion. For acid, however, leakoff is predominantly from wormhole tips

TABLE 1-IDENTIFICATION OF FLUIDS USED IN CORE TESTING

HPG 2% KCI solution gelled with 40 Ibm/1,000 gal hydroxypropyl guar

SGA 15% HCI gelled with a surfactant gelling agent (56 cp at 100°F and 19 cp at

150°F) APGA 15% HCI gelled with acrylamide copolymer

(35 cp at 150°F) XPGA 15% HCL gelled with xanthan biopolymer

(38 cp at 150°F) New system Improved-efficiency gelled 15% HCI having

an initial viscosity of 30 cp at 150°F but increasing to about 1 ,000 cp during leakoff

Viscosilies measured al 170 seconds - , •

218

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TIME (min)

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\ \ \ ,

\ \ \ ,

50 60

Fig. 7 -Effect of pre-existing HPG filter cake on acid fluid loss (see Table 1). (Inltlalleakoff rate = 1.0 mL/mln, 150°F.)

rather than into the fracture face . As a result, one would not ex­pect flow across the core face to have a major effect on test results .

Evaluation of Methods for Acid Fluid-Loss Control One of the techniques commonly used for acid fluid-loss control incorporates a viscous pad preceding the acid to deposit an imperme­able filter cake on the fracture surface. As discussed earlier, previous studies indicate that this technique provides only limited fluid-loss control as a result of rapid filter-cake penetration by acid worm­holes. Data in Fig. 7 show a comparison of fluid loss of 15 % HCl against limestone vs. acid fluid loss against a similar core on which a filter cake of hydroxypropyl guar (HPG) had previously been deposited. As can be seen, the acid leakoff rate is almost totally unaffected by the presence of the filter cake.

Fig. 8 shows a similar test using multiple stages of gelled pad and acid. This test was begun by first injecting an HPG pad for 25 minutes, followed by injection of 15% HCI for 4 minutes. Again, fluid loss during this brief acid injection was unaffected by the pres­ence of the filter cake. Earlier tests (Fig. 3) showed that leakoff of this volume of acid, under these conditions, would create worm­holes to a depth of about 3.9 in. [10 cm]. After the short acid treat­ment, a second stage of pad was injected. Fluid loss during injection of this second pad was much higher than that observed with the initial pad because of the increased leakoff area resulting from the acid wormholes. It was also observed that the effect of the pad on fluid loss is delayed because it must travel the length of the worm-

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Fig. 8-Effect of multiple HPG stages on acid fluid loss (see Table 1). (Initial leakoff rate = 1.0 mL/mln, 150°F.)

SPE Production Engineering, August 1989

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Fig. 9-Effect of SGA's on acid fluid loss (see Table 1).

holes to reach the site of fluid leakoff. As demonstrated, most leakoff occurs at the wormhole tip. After this second pad stage, 15% HCl was again injected. During this period of acid injection, fluid loss remained at a very low level for the entire 25 minutes of the test, compared with the uncontrolIed acid leakoff observed during the initial acid injection. It is interesting to note that fluid loss actualIy declined during acid injection, apparently the result of wormholes being fuII of gel when acid injection resumes. Thus, the fluid leaked off at the wormhole tip is actually gelled water, not acid. Posttest core examination revealed that total wormhole penetration depth was no greater than that produced by the first short period of acid injection. Thus, both fluid loss and wormhole development are con­trolIed by the use of multiple stages of acid and gelIed water.

GelIed acids have found increased use in acid fracturing since the development of more stable acid gelling agents. It is common­ly believed that these gelling agents reduce both fluid loss and acid reaction rate. The two classes of acid gelling agents most often used are synthetic copolymers based on acrylamide and surfactant sys­tems that thicken acid by forming micelIar networks within the acid solution. While both systems exhibit good chemical stability in acid, the surfactant gelIed acids (SGA's) lose viscosity rapidly as tem­peratures approach 150°F [66oq.13 This viscosity loss is not caused by gelling-agent degradation but by disruption of the micellar association network. A unique characteristic of the SGA's is that reaction products produced during acid spending also disrupt this micelIar association and cause the spent acids to revert to a thin fluid. Because this viscosity reduction aids in the recovery of the spent acid after the treatment, it is considered an advantage.

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Fig. ll-Comparison of low-fluid-loss acid system with other fluids (see Table 1).

SPE Production Engineering, August 1989

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Fig. 10-Effect of stable-polymer-type gelling agents on acid fluid loss (see Table 1).

A series of tests was performed to evaluate fluid-loss character­istics of gelled acids. In the first test, fluid loss of 15 % HCl, thick­ened with a surfactant gelling agent, was compared with unthickened acid. As the test results in Fig. 9 show, differences in fluid loss between gelIed and ordinary acid are not as great as might be an­ticipated. This failure to control fluid loss is apparently related to the loss of acid viscosity during spending and the development of wormholes during acid 1eakoff.

The addition of stable polymeric thickeners was found to reduce acid fluid loss significantly. Fig. 10 shows a comparison of fluid­loss properties of 15 % HCl vs. the same acid gelled with two differ­ent polymers. Increasing the acid viscosity significantly reduces acid fluid loss, but the reduction in fluid loss is less than might be antic­ipated on the basis of gelled-acid viscosity. This higher-than­expected fluid loss is apparently related to wormholes created dur­ing acid leakoff. Wormholes extending to a depth of 5.5 in. [14 cm] were produced during the test, even with the gelIed acids. The rapid growth of wormholes during early 1eakoff and the resulting increase in new leakoff area combine to reduce fluid efficiency be­low that expected from a nonreactive fluid. Thus, it appears that improved acid fluid-loss control may require an acid system capa­ble of controlling wormhole growth.

To solve this problem, tests were performed with a gelIed acid having unique rheological properties. This gelled-acid system has an initial viscosity of about 30 cp [0.03 Pa' s]. Spending of the acid during leakoff, however, produces a rise in pH, which initiates a process in which the effective acid leakoff viscosity temporarily rises to about 1,000 cp [I Pa·s]. Complete acid spending triggers

Fig. 12-Fractured limestone block and core drilled from simi-lar block. .

219

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0

0

TEMP 150°F

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""" <> •........... ¢ r.::::::::" <> ............ ¢ ............. ,

2 3 4 5

TIME (mino.S)

Fig. 13-Comparison of fluid loss of various acids against simulated natural fractures (see Table 1). (Initial leakoff rate = 1.0 mL/min.)

a second chemical reaction, which reduces the viscosity of the spent acid to 30 cp [0.03 Pa' s] or less. While it is difficult to measure the duration of this high-viscosity state, rapid spending of bulk sam­ples of the gelled acid indicate that it is probably 5 minutes or less. Fig. 11 presents fluid-loss test results that compare this new sys­tem with ordinary 15% HCI, 15% HCI gelled with an acrylamide copolymer, and water gelled with the same acrylamide copolymer. Of the acids tested, the new system provided the best fluid-loss con­trol, with leakoff approaching the efficiency of gelled water. Ex­amination of cores used in these tests showed that, with this new system, wormhole penetration was only about 0.4 to 0.8 in. [1 to 2 cm], compared with 5.5 in. [14 cm] for gelled acid and 8.7 in. [22 cm] for ordinary 15 % HCI. Examination of cores treated with the new system showed multiple pitting of the core face by many short wormholes rather than any single dominant, deeply penetrat­ing wormhole. This apparently results from repeated initiation and blockage of wormholes during the test.

In addition to tests on permeable limestone cores, flu.id-Ioss tests were also performed against simulated natural fractures. In these tests, cores fractured along their lengthwise axes were used. These cores were prepared by first cutting small (2 x 2 x 12-in. [5 x 5 x 30-cm]) blocks of Indiana limestone notched with a core saw to a depth of about 0.4 in. [1 cm] on opposite sides. Lengths of metal tubing having diameters slightly larger than the notches were centered in each notch. With a shop vise, pressure was ap­plied to the tubing until the specimen fractured under tension. A I-in. [2.54-cm] -diameter core, with a fracture centered along its length, was then drilled from the fractured block. Fig. 12 shows one of these limestone blocks, along with a fracture core prepared with this technique.

Results of fluid-loss tests against these fractured cores are shown in Fig. 13. Test results are similar to those obtained in earlier tests with nonfractured cores (Fig. 11). Again, the new system provid­ed the best fluid-loss control. Acid channeling by the new system into the fracture was limited to only about 0.8 to 1.2 in. [2 to 3 cm]; ordinary 15% HCI penetrated 9.4 in. [24 cm]. Surprisingly, acid gelled with the acrylamide copolymer channeled completely through the core in 12 minutes. Before acid breakthrough, how­ever, actual fluid loss was below that for the ungelled acid.

Conclusions 1. Acid fluid loss into permeable limestone results in the crea­

tion of wormholes, with final lengths determined by leakoff rate, temperature, and acid concentration.

220

2. Wormholes grow very rapidly during the early stages of acid leakoff before approaching a spending-limited maximum length.

3. Once wormholes develop, the differential pressure distribu­tion is such that almost all fluid loss occurs from wormholes rather than into the fracture face.

4. Wormhole growth and the resulting creation of additional new surface area from which leakoff occurs make acid fluid loss very difficult to control.

5. As a result of rapid wormhole penetration, filter cakes previ­ously deposited on fracture surfaces have little effect on acid fluid loss.

6. Wormhole growth also reduces the efficiency of gelled acids compared with gelled nonreactive fluids.

7. Systems designed to block wormhole growth show promise for improving the efficiency of acid fracturing treatments.

References 1. Nierode, D.E. and Kruk, K.F.: "An Evaluation of Acid Fluid Loss

Additives, Retarded Acids, and Acidized Fracture Conductivity, " paper SPE 4549 presented at the 1973 SPE Annual Meeting, Las Vegas, Sept. 30-0ct. 3.

2. Hoefner, M.L. and Fogler, H.S.: "Fluid-Viscosity and Reaction-Rate Effects During Carbonate Acidizing: Application of a Network Model," SPEPE (Feb. 1989) 56-62.

3. Davis, J.J., Mancillas, G., and Melnyk, J.D.: "Improved Acid Treat­ments by Use of the Spearhead Film Technique," paper SPE 1164 presented at the 1965 SPE Rocky Mountain Regional Meeting, Bill­ings, MT, June 10-11.

4. Coulter, A.W. et al.: "Alternating Stages of Pad Fluid and Acid Pro­vide Improved Leakoff Control for Fracture Acidizing," paper SPE 6124 presented at the 1976 SPE Annual Technical Conference and Ex­hibition, New Orleans, Oct. 3-6.

5. Lee. W.S.: "Geometry Determination for Multi-Stage Acidizing Treat­ments With or Without Viscous Preflush," paper SPE 14515 present­ed at the 1985 SPE Eastern Regional Meeting, Morgantown, WV, Nov. 6-8.

6. Schriefer, F.E. and Shaw, M.S.: "Use of Fine Salt as a Fluid-Loss Material in Acid Fracturing Stimulation Treatments," paper SPE 7570 presented at the 1978 SPE Annual Technical Conference and Exhibi­tion, Houston, Oct. 1-3.

7. Crowe, C.W., Martin, R.C., and Michaelis, A.M.: "Evaluation of Acid Gelling Agents for Use in Well Stimulation," JPT(Aug. 1981) 415-24.

8. Rowan, G.': "Theory of Acid Treatment of Limestone Formations," J. Inst. Petrol. (1957) 45, No. 431, 321-24.

9. Daccord, G., Touboul, E., and Lenormand, R.: "Carbonate Acidiz­ing: Toward a Quantitative Model of the Wormholing Phenomenon," SPEPE (Feb. 1989) 63-68.

10. Gdanski, R.D. and Norman, L.R.: "Using the Hollow-Core Test To Determine Acid Reaction Rate," SPEPE (March 1986) 111-16.

11. Holditch, S.A.: "Factors Affecting Water Blocking and Gas Flow From Hydraulically Fractured Gas Wells," JPT (Dec. 1979) 1515-24.

12. Shaughnessy, C.M. and Kunze, K.R.: "Understanding Sandstone Acidizing Leads to Improved Field Practices," JPT (July 1981) 1196-1202.

13. Norman, L.R.: "Properties and Early Field Results of a Liquid Gel­ling Agent for Acid," paper SPE 7834 presented at the 1978 SPE Pe­troleum Technology Symposium, Hobbs, Oct. 30-31.

SI Metric Conversion Factors cp x 1.0* E-03 Pa's OF (OF - 32)/1.8 °C gal x 3.785 412 E-03 m3

in. x 2.54* E+OO cm Ibm x 4.535924 E-Ol kg psi x 6.894757 E+OO kPa

* Conversion factor is exact. SPEPE Original SPE manuscript received for review Sept. 27, 1987. Paper accepted for publica· tion May 17,1988. Revised manuscript received Sept. 6,1988. Paper (SPE 16883) first presented at the 1987 SPE Annual Technical Conference and Exhibition held in Dallas, Sept. 27-30.

SPE Production Engineering, August 1989