Copyright 2005, International Petroleum Technology Conference This paper was prepared for presentation at the International Petroleum Technology Conference held in Doha, Qatar, 2123 November 2005. This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an proposal submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the International Petroleum Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the International Petroleum Technology Conference, its officers, or members. Papers presented at IPTC are subject to publication review by Sponsor Society Committees of IPTC. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the International Petroleum Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, IPTC, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract Carbonate acidizing continues to be a vital process for improving the production of oil and gas wells. Laboratory studies and field evaluations of carbonate acidizing during the past 30 years have shown a continually improved understanding of the fundamental issues. This paper discusses the current state of the advances in carbonate stimulation. Average reactivity data for several limestones and dolomites are presented and can be used as improved default values for simulators. Wormhole development and structure during matrix acidizing are viewed as symmetry dominated processes controlled by fluid flow that obeys the native permeability contrasts within the matrix. The resulting simplification allows for rational treatment designs for matrix acidizing of carbonates. Zonal coverage of long carbonate sections, whether vertical or horizontal, remains a challenge. However, using the 75-25 rule for horizontal wells, creating a thief zone at the bottom or toe of the well, and utilizing the top decade of permeability rule can aid in achieving reasonable designs for maximizing productivity. The three fundamental issues of fracture acidizing are addressed: reactivity control, fluid loss control, and conductivity generation. Because synthetic polymers for acid gellants have made reactivity control easy, fluid loss control is usually the most dominant issue to be addressed in fracture acidizing. Carbonate Reactivity Several models are available to predict the spending of acid on carbonates. Some calculate the spending during fracture acidizing while some calculate the spending during matrix acidizing and wormhole generation. The earliest spending tests were simple spending time experiments in open beakers. However, it soon became clear that this was an inadequate procedure because mass transport definitely plays a role. Experiments conducted on quarried limestone and dolomite during the 1970s gave our first estimates of the temperature dependence of the reactivity of HCl on carbonates.1,2 These experiments suggested that limestones had incredibly high

reactivity with acid such that one could assume a mass transport limited process. Laboratory experiments during the 1980s, however, could not support that conclusion and eventually it became understood that even the reaction of HCl with limestones was a balanced process.3 This means that while high-reactivity limestones may be mass transport dominated, they are never truly mass transport limited. Furthermore, their reactivity seems to be about 1/100th the reactivity of the originally reported reactivity, and the temperature dependence of the reactivity is much lower than originally reported.4,5

The reactivity of various oilfield carbonates has been measured with optimized rotating disc experiments for several years. Cores from producing carbonates in 13 countries have undergone significant testing to provide temperature dependant reactivity data from 70 cores. Sufficient data has been collected to allow analysis and averaging of the reactivities from those cores. Fig. 1 reports the average reactivity of 30 limestones and 20 dolomites, normalized to a reaction order of 0.40 for easy comparison. The carbonates for these subsets were chosen based on their having at least 93% composition as either limestone or dolomite. Another 20 carbonates fell into the category of being mixed carbonates.

Fig. 1Normalized and averaged reactivity of carbonates.

The average energy of activation, Ea, which represents

temperature dependence, for the limestones was 2.5 kcal/mole, significantly lower than the 15.2 kcal/mole historically assumed. In fact, it makes much more sense that a reaction as fast as HCl on a limestone should have a low Ea rather than a high Ea. The average Ea for the dolomites was 5.9 kcal/mole, again significantly lower than the 22.4 kcal/mole historically assumed. Furthermore, notice that the reactivity of the average

IPTC 10693

Recent Advances in Carbonate Stimulation R. Gdanski, Halliburton

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limestone and average dolomite are the same at 200F. At 100F, the reactivity of an average limestone is about twice that of the average dolomite.

Fig. 2 shows the reactivity data for all 30 limestones at the average limestone reaction order of 0.36. Notice that limestone reactivity can vary by a factor of 10 at almost any temperature. As a consequence, it becomes very important that the reactivity data of each carbonate formation be measured. The average reaction rate constant, Rk, at 100F using the average reaction order, Ro, of 0.36 was 7.7E-5 with an Ea of 2.5 kcal/mole. This average can be used as default reactivity data for limestones, if no reactivity information is available on a specific formation. However, the figure clearly shows that some limestones react as slowly as dolomites.

Fig. 2Normalized reactivity of limestones.

Fig. 3 shows the reactivity data for all 20 dolomites at the average dolomite reaction order of 0.44. Notice that dolomite reactivities can vary by a factor of 3 at almost any temperature, and so are better behaved than limestones. Still, the variation is significant enough that it is important that the reactivity data of each carbonate formation be measured. The average reaction rate constant, Rk, at 100F using the average reaction order, Ro, of 0.44 was 5.2E-5 with an Ea of 5.9 kcal/mole. This average can be used as default reactivity data for dolomites, if no reactivity information is available on a specific formation. However, some dolomites are as reactive as an average limestone.

Fig. 3Normalized reactivity of dolomites.

The reactivity of acid systems gelled with synthetic polymers has been well studied.6 In general, it was found that the reactivity of acid on carbonates is reduced by about a factor of 10 in acid gelled with synthetic polymers. Acids gelled with surfactants, however, do not exhibit lower reactivity data, though they do spend slowly under application conditions by reducing mass transport. All gelled acids give enhanced performance by reducing fluid loss during fracture acidizing, or improving zonal coverage during matrix acidizing. The Ea is not affected by gelling the acid with either synthetic polymers or surfactants. Therefore, plain acid reactivity data properly generated with optimized rotating disc experiments can be useful for a broad range of acid systems. Matrix Acidizing In 1979, SPE published Monograph Volume 6 of the Henry L. Doherty Series entitled Acidizing Fundamentals, which was coauthored by Bert Williams, John Gidley, and Robert Schechter.7 Matrix acidizing of carbonates is extensively discussed in the Acidizing Fundamentals monograph. A method is given for calculating the spending of acid down a dominant wormhole in either turbulent or laminar flow. Calculations of acid spending lengths can be performed with or without fluid leakoff. Unfortunately, three fundamental questions remained unanswered at that time, which prevented use of the published concepts:

1. How many dominant wormholes are generated? 2. What is the spatial distribution of these dominant

wormholes? 3. What is the leakoff profile from the dominant

wormholes?

Considerable laboratory work has been conducted during the intervening years8-12 but almost exclusively in short-core tests. These tests suffer from restrictions imposed by linear flow and the small dimensions of the core. The linear flow tests give the following answers to the three questions above:

1. There is only one dominant wormhole. 2. The single dominant wormhole extends linearly through

the length of the core. 3. Leakoff is linearly out the end of the core.

Clearly these answers are of limited use in field

applications of radial flow. A new theory has recently been introduced and discussed13,14 that relies on the existence of symmetry patterns first published by Daccord.15 The presence of symmetry in matrix acidizing of carbonates was assumed in the development of the new model that proposes to answer the three questions left unanswered 25 years ago. The numerical results from the model are in qualitative agreement with generally held guidelines for matrix acidizing. The model has been validated by field treatments and indicates that only fractions of a pore volume (PV) are required to reach a certain distance from the wellbore. This stands in stark contrast to predictions from linear experiments that suggest no less than 1 PV will be required, and that most often multiple PVs may be required to reach a certain distance from the wellbore. In addition, the simplification brought about by the new theory made general matrix-acidizing treatment designs a simpler process.

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The new theory is, in fact, complementary to the detailed understanding of wormhole development revealed by the years of linear flow experiments. The effect of the Damkhler number on wormhole structure and the existence of an optimum Damkhler number are clearly correct. However, the primary revelation of the modeling work from the new theory is that wormhole penetration distance is not really controlled by reactivity, but by volumetric invasion issues that are controlled by the accessible porosity of the matrix, the rheological nature of the acidizing fluid, and the native permeability anisotropy of the matrix. Further, permeability improvement of a carbonate above 100-fold renders that portion of the matrix invisible from a production viewpoint. This principle is shown in Fig. 4 by comparing the calculated skin at several levels of permeability improvement. As such, knowing the exact nature and structure of the wormhole pattern becomes a moot point. It is not necessary to know whether the wormhole pattern is highly ramified or has a simple dominant wormhole pattern. It is sufficient just to know that the permeability has been improved by at least 100-fold by the acidizing process. Indeed, a recent study comparing a classical spending approach with the new simplified approach using a matrix-acidizing simulator indicated that both provide nearly identical results with wormhole penetration predominantly controlled by volumetric invasion.16

Fig. 4Effect of permeability improvement on skin.

The new theory proposes specific answers for the three remaining questions left unanswered 25 years ago. The spatial distribution around the wellbore is as sets-of-six. The overall invasion pattern of the sets is governed by the native permeability contrast. This means that the patterns elongate in the most permeable directions. The sets of wormholes are spaced along just enough of the length of the wellbore to satisfy that the Damkhler number at the leading edge of invasion is near the optimum. Sets of wormholes die out as their length from the wellbore to the tip become the same as their separation along the length of the wellbore. Wormhole die-out occurs due to pressure interference between the sets from the 3-D leakoff, as manifested by 3-D wormhole branching. As a result, the number of dominant wormhole sets decreases during the course of fluid injection. Fluid loss is

dominated by 3-D wormhole branching and not really by wall leakoff as is the case in fracture acidizing.

The fundamental driver for all these manifestations in the new theory is that wormhole patterns and symmetry arise as a consequence of normal fluid flow through the porous media. Wormholes are not created in an independent fashion that follows paths of unpredictable direction. Stated differently, wormholes follow behind fluid invasion, and fluid invasion is controlled by the native permeability contrasts in the formation.

Many of the predictions of the model are in good agreement with classical guidelines of matrix acidizing normal carbonates. For example, typical acid designs that produce good stimulation under matrix flow conditions use about 100 gal/ft of 15% HCl as a reasonable optimum. Calculations show that this volume should generate a -3 to -3.5 skin, depending on porosity and permeability contrasts, as shown in Fig. 5. Doubling the acid volume will give a 50% increase in wormhole distance, but it will not dramatically decrease the skin. As another example, nominal zonal coverage rates for plain acid are about 10 ft of zone for every bbl/min of injection rate. Calculations show that once the acid has penetrated about 1 ft from the wellbore, this classical zonal coverage rate is situated near the optimum Damkhler number. As such, a 30-ft zone requires an injection rate of 3 bbl/min or higher for good zonal coverage. A pump rate of 10 bbl/min into a long horizontal well will probably only treat the first 100 ft of zone, unless extraordinary efforts are taken to achieve diversion.

Fig. 5Acid design chart. Zonal Coverage An important aspect of acidizing carbonates is achieving good zonal coverage with the acid. If the zones are relatively short, this can likely be accomplished simply with rate, or perhaps rate and a little viscosity in the acid.17 However, once the zone becomes longer than about 100 ft, zonal coverage becomes much more difficult. If the producing interval is in the range of 1,500 ft, not only is good zonal coverage difficult to achieve, it can also be very expensive. Questions naturally arise as to: (1) how much of the zone is really going to be productive, (2) does the entire horizontal interval need to be acidized well, (3) what is the damage distribution along the wellbore, (4) has the well produced long enough that there is a

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reservoir pressure gradient along the wellbore, and (5) what is the best way to get acid all the way to the bottom (or toe) of the well?

The Top Decade Rule One of the first principles to understand regarding acid diversion, or zonal coverage, is the purpose of diversion. Specifically, the purpose of diversion is to make zones having similar permeabilities produce similarly by the removal of damage and/or stimulating to about -3 to -3.5 skins. Diversion cannot induce a 0.1 md zone to produce the same as a 1 md zone, unless the 0.1 md zone has 10 times the pressure or 10 times the length. Furthermore, laboratory experiments attempting to divert acid from one reactive core to another have shown that the maximum flow contrast that can be diverted is about 10 to 20.18 However, if both cores have nearly the same permeability and one is damaged by a fairly thin skin, then diversion can be very effective and can easily penetrate the damage, even at high initial flow contrasts.

Taken together, these two concepts can be used to develop a guideline for deciding how much of an interval is likely to contribute significantly to production, and how much is likely to be within the grasp of acid diversion. (An exception to this discussion would be the use of mechanical diversion.) The approach is to create a normalized cumulative permeability distribution plot to identify how much of the zone is in the top decade of permeability.

Fig. 6 shows a hypothetical semi-log plot of cumulative zone height vs. permeability. The average permeability for the formation is about 5 md, but the permeability ranges from 0.1 to 280 md. The dashed lines show that only 10% of the total zone height is in the range of 28 to 280 md, or the top decade of permeability. As a result, achieving good zonal coverage will be an extraordinary challenge with nonmechanical approaches. In addition, it can readily be understood that about 30% of the zone, with permeability ranging from 0.1 to 3 md, will probably not contribute significantly to production until the higher permeability sections have been substantially depleted.

Fig. 6Broad permeability distribution.

Fig. 7 shows a hypothetical formation with a narrow distribution of permeabilities. The average permeability is still approximately 5 md, but the permeability only ranges from

about 1 to 22 md. The dashed lines indicate that nearly 90% of the zone is within the 2.2 to 22 md range, indicating that typical diversion techniques should be quite effective at covering the entire interval. In addition, most of the zone will contribute production throughout the life of the well.

Fig. 7Narrow permeability distribution. Rate and Viscosity Once the length of interval to be acidized has been identified, the next challenge is to assure that most of that interval is effectively acidized. Unfortunately, the acidizing process itself generates a permeability improvement in the matrix that works against good zonal coverage, particularly under bullhead conditions. There is, however, a natural zonal coverage rate that is essentially the optimized acid injection rate for creating fast developing wormholes. Experience and simulations indicate that this optimum injection rate, once acid has penetrated beyond a few inches from the wellbore, is approximately 1 bbl/min for every 10 ft of wellbore coverage. As such, an acid treatment conducted at 20 bbl/min should be able to effectively cover about 200 ft of interval. Viscosifying the acid to about 20 cp at bottomhole static temperature (BHST) conditions is thought to double the zonal coverage rate to about 20 ft for every 1 bbl/min of pumping rate. It is also known that very high viscosities (perhaps >200 cp at BHST), such as with emulsified acids or crosslinked acids, also improve zonal coverage, but an effective zonal coverage rate has not been estimated.

It should be mentioned that one of the challenges of zonal coverage, or diversion, in bullheaded treatments is to displace nonreactive wellbore fluids into the matrix ahead of the acid treatment. Doing so requires keeping the wellbore pressure sufficiently high and for sufficient time to allow acid to displace the entire wellbore. Waiting until late in the treatment to reach maximum injection rate or to use viscous acid can significantly reduce the amount of zone effectively treated with acid. Therefore, it is important that the acid treatments reach maximum allowed injection rate as soon as possible after the acid treatment commences.

Effective zonal coverage may also require stages of highly viscous diverting fluids. The concept is to fill the recently created wormhole patterns with diverter, such as high quality foam or acid-stable crosslinked fluids. The diverter stage residing within the wormhole pattern can then act as a

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reservoir of diverter while the following acid stages bypass the treated zone as they travel along the wellbore. Create a Thief Zone at the Bottom Experience has demonstrated that during bullheaded treatments of long intervals it is difficult to get acid to travel much beyond the end of the pipe in the absence of effective diversion. Even with effective diversion, experience and numerical simulations demonstrate that the bottom 30% of the zone can be very difficult to stimulate. The source of this challenge is considered to be a combination of the ease of continued acid flow into stimulated zones of -3 skin (or better), and the resistance of forcing the original nonacid wellbore fluids into the damaged or unstimulated sections at the bottom of the well before the acid arrives.

Simulations suggest that an effective solution to this problem is to pre-acidize the bottom (or toe) of the well to create a thief zone of -3 skin or better.19 The zone will not act as a true thief zone as would be the case of a highly naturally fractured section, but it will more easily enable the original wellbore fluids to be quickly displaced by the acid treatment. The pseudo-thief zone at the bottom can be created using coiled tubing and a small amount of acid. A typical design would be to pump 2,000 gal of 15% HCl at 2 bbl/min through coiled tubing positioned at the bottom (or toe) of the well. The tubing is then retrieved and the acid treatment pumped at high rates using viscous acid and effective diverting methods. This method has been applied successfully in long vertical wells, and may be most efficient in horizontal wells of perhaps less than 1,500 ft of perforated or exposed length. However, a modification of this technique involving perforating and acidizing the toe, followed by perforating and acidizing the remaining interval with emulsified acid and ball sealers, has been used successfully in 6,000-ft horizontals having about 3,000 ft of selectively perforated length.20 The 75-25 Rule Horizontal wells present a unique challenge due to the extended lengths of interval as compared to typical vertical wells. Acid designs based on vertical guidelines, such as 100 gal/ft of 15% HCl to achieve a skin of -3 or better, become prohibitively expensive for a 3,000-ft horizontal well. Several investigators have used numerical simulations to study ways of optimizing acid designs for horizontal wells.21,22 These and other studies are in general agreement with one another and indicate the following two important results.

First, suppose that costs restrict the size of an acid treatment to only 15 to 35% of a full classical design. The question arises as to whether it is better to treat the entire zone evenly with the acid, or acidize only a few places well. The results from the calculations clearly indicate that it is far better to acidize a few places well, rather than acidizing everything poorly.

Second, a decision must be made as to how much of the zone to acidize properly, perhaps 15%, or 25%, or 35%. The calculations indicate that the more horizontal length that is acidized, the more production that is possible. However, an evaluation of the trends indicates that acidizing 25% of the horizontal length properly will provide approximately 75% of the productive potential if all the length is acidized properly.

For this author, this important result became the 75-25 rule. Furthermore, technical conversations with others who have independently verified these calculations suggest that the 25% length should be broken into five to nine pieces along the length of the horizontal well. Choosing the number of pieces and their positions may depend on identifying (1) preferred locations with logging techniques, (2) locations of convenience, or (3) other design considerations. Fracture Acidizing The use of fracture acidizing to enhance the production of carbonate formations continues to be an effective process. Suggestions and claims regarding what is important for achieving a successful treatment have fluctuated over the past 30 years to include special acid systems, special placement techniques, etc. Nevertheless, three fundamental issues must be addressed to achieve a successful fracture-acidizing treatment. A focus on only one or two of these issues can result in poor performance. Reactivity Control The first fundamental issue is that of reactivity control. Dissolution of carbonate is the means by which conductivity is generated. The dissolution is controlled by reactivity, which is affected by both carbonate composition and temperature. An improper understanding of reactivity may lead to a choice of fluid that is inappropriate for the reservoir conditions. Therefore, it is very important to understand the issues of reactivity discussed in the earlier section. There was a time when almost everyone considered reactivity control to be the single most important issue in providing effective fracture-acidizing treatments. This conclusion was based on the combination of (1) an improper understanding of limestone reactivity, and (2) the lack of effective fluid loss control measures provided by synthetic polymer gelled acids. Currently, reactivity control is sufficient that fluid loss control has been clearly exposed as the dominant barrier to effective fracture-acidizing treatments.

Guidelines have been developed for choosing an appropriate method for achieving reactivity control. Low reactivity carbonates at cool reservoir conditions need acid systems that have not further lowered the acid reaction rate constants. Foamed-acid and surfactant gelled acids are examples of systems known to be quite effective in low reactivity carbonates.

Moderate reactivity carbonates can also be treated with foamed acid and surfactant gelled acids, but synthetic polymer gelled acids provide a level of reactivity control and fluid loss control that makes them widely applicable.

Treatments on high reactivity carbonates, or moderate reactivity carbonates at high temperatures, should generally employ acid systems using synthetic polymers to viscosify the acid. These systems provide excellent reactivity control and mass transport control. Fluid Loss Control The second fundamental issue involved in successful fracture-acidizing treatments is fluid loss control. This is perhaps the primary cause of failure for many fracture-acidizing treatments. In sand fracturing, excessive fluid loss can result in

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screenouts and a premature shutdown of the treatment. In acid fracturing, a screenout is incredibly difficult to achieve and only very rarely occurs, even with excessive fluid loss. The absence of the feedback provided by a screenout has made it easy for our industry to ignore the issue of excessive fluid loss during fracture-acidizing treatments. Yet, if fluid efficiency drops to the point that the treating pressure no longer stays above fracture-extension pressure, it indicates that all the acid is leaking off into the formation. When this happens, the treatment has become a large matrix-acidizing treatment and the etched length will be quite short. The result will be a well that gives a high flush production, but quickly falls to a much lower value over the long term. The property that gives good long-term production increase is etched length of sufficient conductivity. Etched length is different from created length. Nonacid fluids might be used to create a long fracture, but if the acid has excessive fluid loss, the etched length will be very short and the long-term production increase will be disappointing.

The single most significant step to improve fluid loss control in fracture-acidizing treatments is to viscosify the acid. All other efforts to improve fluid loss control will be relatively useless unless the first step is using viscous acid. There are a number of ways to viscosify acid, including: natural polymers synthetic polymers surfactants foams emulsions

Laboratory testing using hollow limestone cores, even

under severe test conditions, has clearly demonstrated that viscosity has a powerful effect on providing the first level of fluid loss control.23 This first level of fluid loss control can be achieved with as little as 20 cP of viscosity at 511/sec at BHST. This benchmark viscosity provides a good guideline for deciding how much viscosity is enough for first-level fluid loss control. It is generally sufficient viscosity in situations where matrix permeability is less than about 1 md. Under such conditions, the choice of viscosifier will largely be driven by the reactivity issues mentioned earlier.

Some formation conditions require even more fluid loss control than what is provided by first-level approaches, and so may require a second level of fluid loss control. The second-level of improved fluid loss control can be achieved by using either large solids or much higher fluid viscosities. Studies have shown that large solids can be very effective in providing this second level of fluid loss control. The solids should be at least 100-mesh in size, and can easily be 40- to 60-mesh solids. The solids must be large due to the relatively larger diameters of wormholes caused by acid leakoff as compared to the original pore throats. Pore throats can be bridged with particles of a few microns in diameter, but wormholes require much larger particles. The solids can be sand, oil-soluble resins, or anything else deemed useful. Concentrations should start at 0.25 lb/gal and should be increased in 0.25-lb/gal increments if an acid stage does not maintain fracture extension pressure. Fracture-acidizing treatments using 1 to 2 lb/gal of solids have been successfully conducted and

provided significantly improved sustained production increases.

If higher viscosities are chosen for achieving the second level of fluid loss control, the target viscosities should be in the range of a few hundred centipoise, perhaps 100 to 300 cP under downhole conditions. This can be achieved with live acid crosslinkers, such as zirconium, and near-spent acid crosslinkers. Live acid crosslinkers provide high viscosity in the fracture itself, while near-spent acid crosslinkers provide high viscosity in the matrix after leakoff and at the leading edge of acid flow in the fracture. Foams and emulsions can also provide these higher viscosities. The choice of fluid may depend on such factors as acceptable friction pressures in the tubing, the availability of materials such as nitrogen, and whether leakoff is perceived to be dominated by matrix loss or natural fracture loss. The higher live-acid viscosities may be preferable when leakoff is dominated by natural fractures. Conductivity Generation The third fundamental issue in successful fracture-acidizing treatments is the generation of acceptable conductivity. Proper reactivity control and proper fluid loss control are prerequisites for obtaining good conductivity. The first two issues assure that it is even possible to dissolve rock at a significant distance from the wellbore in the created fracture. However, they are not sufficient to assure that good conductivity is truly generated. Conductivity generation requires that two additional goals be met: (1) sufficient carbonate removal, and (2) removal in an uneven manner, so that good conductivity can be generated.

Sufficient rock removal is an easy issue to overlook. Simulations can readily show that live acid can travel down a fracture for well over 200 ft when proper reactivity control is addressed. This factor can lead to the assumption that if acid gets there, then conductivity will be there. Unfortunately, the situation is a bit more complicated. Simple calculations can highlight the issue.

Fig. 8Created fracture length.

Fig. 8 shows the results of calculations of created length

based on simple mass balance. A fracturing simulator was used to estimate a nominal created width of 0.15 in. using a 20 cP fluid, which is the design criterion for the first level of fluid

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loss control. Several fluid efficiencies from 5 to 30% were used to calculate the created length vs. injected fluid volume.

Notice that for a created length of 200 ft, it is relatively easy to create such a fracture, even with poor fluid efficiencies. At a fluid efficiency of only 10%, meaning 90% of the fluid is leaking off into the matrix, it requires about 400 gal/ft to create two 200-ft fracture wings, but at a fluid efficiency of 30%, it requires only 130 gal/ft to create two 200-ft fracture wings.

The situation is much different when considering the rock dissolving power. Fig. 9 shows the results of calculations of etched length based on simple mass balance. A nominal etched width of 0.10 in. was used based on laboratory observations that conductivity does not usually rise above 2,000 md ft unless the etched width reaches 0.10 in., or 0.05 in. from each face of the fracture. It was assumed that 15% HCl was used to etch the fracture, and so a rock-dissolving power of 1.8 lb/gal was used in the calculations. Finally, several rock dissolving efficiencies ranging from 20 to 70% were used to calculate the possible etched length vs. injected acid volume. The rock dissolving efficiencies recognize that under high fluid-loss conditions, much of the rock-dissolving power goes to creating wormholes, not etched width.

Fig. 9Over-simplified etched length.

Suppose that at 30% fluid efficiency, the acid is able to spend mostly on the fracture face before leaking into the matrix such that the dissolving efficiency is high at 70%. Fig. 4 shows that it will require about 450 gal/ft of 15% HCl to dissolve exactly 0.10 in. (0.05 in. from each face) down the length of two 200-ft fracture wings. However, if fluid loss control is poor, and fluid efficiency is only 10% and dissolving efficiency is low at 30%, it will require about 1,000 gal/ft of 15% HCl to create an etched width of 0.10 in. in the 200-ft fracture.

Figs. 8 and 9, when taken together in a simplified fashion, suggest that a small fracture-acidizing treatment of about 250 gal/ft, even with good efficiencies, will probably only reach about 75 ft. Long-term production increase is not likely to be impressive with such a treatment. However, a serious fracture-acidizing treatment of about 500 gal/ft will be capable of 150- to 200-ft etched lengths. Of course, modern computer simulators are capable of modeling the realities much better than this simplistic approach, but the point remains that

conductive length can only be created by pumping sufficient dissolving power.

In brief, good fracture-acidizing designs should recognize that creating good conductivity means pumping sufficient dissolving power to remove the amount of rock necessary to create conductivity, and so will probably be about 500 gal/ft or greater in volume. Conclusions The study of carbonate acidizing has progressively improved the success of acid stimulation treatments. While much of the science can be considered quite complex, a number of simplifying guidelines have been developed that can improve the application of modern acidizing theories. These theories have provided the following conclusions: The reactivities of oilfield carbonates have been

measured in the laboratory and exhibit fairly low energies of activation, consistent with a mass transport dominated process.

New default reactivity values for limestones and dolomites have been proposed.

The average limestone and dolomite have similar reactivities above approximately 200F.

Carbonate spending is often a mass transport dominated process, but it is not a mass transport limited process.

The three fundamental issues that must be addressed for successful fracture acidizing are reactivity control, fluid loss control, and conductivity generation.

Reactivity control is most easily achieved by the proper choice of acid viscosifier.

The first level of fluid loss control must be to viscosify the acid to at least 20 cP at BHST conditions.

The second level of fluid loss control can be either choosing large solids or acid viscosities in the few hundred cP range.

Proper conductivity generation requires pumping sufficient acid volume, good zonal height coverage, and uneven etching of the fracture face.

A new matrix-acidizing theory based on symmetry has significantly improved the understanding of the performance of acid treatments.

Wormhole length in matrix acidizing is dominated by volumetric issues such as accessible porosity, permeability contrast, and acid volume.

Acidized permeability improvement is provided by the wormhole diameters and is dominated by spending issues such as reactivity, carbonate composition, acid strength, and contact time.

Potential zonal coverage for diverting matrix-acidizing treatments is often subject to the Top Decade Rule.

An optimum length of horizontal well to be acidized can be calculated by the 75-25 Rule.

Creating a thief zone at the bottom of a well with a small amount of acid can significantly improve the success of bullheaded, diverted acid treatments.

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8 IPTC 10693

References 1. Lund, K., Fogler, H.S., McCune, C.C., and Ault, J.W.:

Acidization - II. The Dissolution of Calcite in Hydrochloric Acid, Chemical Engineering Science, Vol. 30 (1975) 825-835.

2. Lund, K., Fogler, H.S., and McCune, C.C.: Acidization - I. The Dissolution of Dolomite in Hydrochloric Acid, Chemical Engineering Science, Vol. 28 (1973) 691-700.

3. Roberts, L.D. and Guin, J.A.: The Effect of Surface Kinetics in Fracture Acidizing, SPEJ (Aug. 1974) 385-395.

4. Gdanski, R.D. and van Domelen, M.S.: Slaying the Myth of Infinite Reactivity of Carbonates, paper SPE 50730 presented at the 1999 International Symposium on Oilfield Chemistry, Houston, TX, Feb. 16-19.

5. Gdanski, R.D. and van Domelen, M.S.: Understanding the Finite Reactivity of Carbonates, paper No. 26 presented at the 2000 NIF Oil Field Chemicals Symposium, Fagernes, Norway, Mar. 20-22.

6. Gdanski, R.D. and Norman, L.R.: The Effect of Filterable Solids on Acid Reaction Rates, SPEPE (March 1986) 111-116.

7. Williams, B.B., Gidley, J.L. and Schechter, R.S.: Acidizing Fundamentals, Monograph Volume 6, Henry L. Doherty Series, SPE-AIME, Dallas (1979).

8. Hoefner, M.L. and Fogler, H.S.: Pore Evolution and Channel Formation During Flow and Reaction in Porous Media, AIChEJ 34 1 (1988) 45-54.

9. Fredd, C.M., Tjia, R. and Fogler, H.S.: The Existence of an Optimum Damkhler Number for Matrix Stimulation of Carbonate Formations, paper SPE 38167 presented at the 1997 European Formation Damage Conference, The Hague, The Netherlands, Jun. 2-3.

10. Wang, Y., Hill, A.D. and Schechter, R.S.: The Optimum Injection Rate for Matrix Acidizing of Carbonate Formations, paper SPE 26578 presented at the 1993 Annual Technical Conference and Exhibition, Houston, TX, Oct. 3-6.

11. Bazin, B., Roque, C., Chauveteau, G. and Boutca, M.: Acid Filtration in Dynamic Conditions to Mimic Fluid Loss in Acid Fracturing, paper SPE 38168 presented at the 1997 European Formation Damage Conference, The Hague, The Netherlands, Jun. 2.

12. Buijse, M.A.: Understanding Wormholing Mechanisms Can Improve Acid Treatments in Carbonate Formations, paper SPE 38166 presented at the 1997 European Formation Damage Conference, The Hague, The Netherlands, Jun. 2-3.

13. Gdanski, R.D.: A Fundamentally New Model of Acid Wormholing in Carbonates, paper SPE 54719 presented at the 1999 European Formation Damage Conference, The Hague, The Netherlands, May 31Jun. 1.

14. Gdanski, R.D.: The Symmetry of Acid Wormholing in Carbonates, paper No. 25 presented at the 2000 NIF Oil Field Chemicals Symposium, Fagernes, Norway, Mar. 20-22.

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

16. Glasbergen, G., van Batenburg, D., van Domelen, M., and Gdanski, R.: Field Validation of Acidizing Wormhole Models, paper SPE 94695 presented at the 2005 European Formation Damage Conference, Scheveningen, The Netherlands, May 25-27.

17. Paccaloni, G. and Tambini, M.: Advances in Matrix Stimulation Technology, JPT (March 1993) 256-263.

18. Thompson, K. and Gdanski, R.D.: Laboratory Study Provides Guidelines for Diverting Acid with Foam, paper SPE 23436 presented at the 1991 Eastern Regional Meeting, Lexington, KY, Oct. 22-25.

19. Jones, A.T. and Davies, D.R.: Quantifying Acid Placement: The Key to Understanding Damage Removal in Horizontal Wells, paper SPE 31146 presented at the 1996 International Symposium on Formation Damage Control, Lafayette, LA, Feb. 14-15.

20. Buffet, M., Derbez, E., Leschi, P., and MacRae, S.: Pushing the Limits in Extra-Long Cased Horizontal Drains Acidification: Use of Double Trigger Perforation Technique to Maximize Productivity and Optimize Rig Time, paper SPE 78543 presented at the 2002 Abu Dhabi International Petroleum Exhibition and Conference, Oct. 13-16.

21. da Motta, E.P., Hill, A.D., and Sepehrnoori, K.: Selective Matrix Acidizing of Horizontal Wells, SPEPE (Aug. 1995) 157-164.

22. Frick, T.P. and Economides, M.J.: A Case Study for the Matrix Stimulation of a Horizontal Well, paper SPE 23806 presented at the 1992 International Symposium on Formation Damage Control, Lafayette, LA, Feb. 26-27.

23. Gdanski, R.D.: Fluid Properties and Particle Size Requirements for Effective Acid Fluid-Loss Control, paper SPE 25894 presented at the 1993 Rocky Mountain Regional/Low Permeability Reservoirs Symposium, Denver, CO, Apr. 12-14.