Effective Sandstone Acidizing - Best Practice

Effective Sandstone Acidizing Sandstone 2000TM

F-3374R 05/97

Effective Sandstone Acidizing Introduction Sandstone acidizing technology has improved significantly over the last 5 years as a result of field analysis, fundamental research, and applied research. Older theories predicted that after sandstone acidization, approximately 10% HCl, approximately 3,500 mg/L of silicon, a small amount of aluminum, and a possible trace of sodium should exist in the initial undiluted returns. Those theories proved to be inaccurate in 1984 when samples from a Gulf coast well were obtained after sandstone acidization. Our analysis revealed almost no acid, no silicon, and large amounts of aluminum and sodium. Further study and research revealed a complex reaction process based on acid concentration, temperature, and the target formation mineralogy. Based on this research, the Sandstone 2000™ Acid System was developed. Approximately 90% of the wells treated with the Sandstone 2000 Acid System have been returned to production with a two- to four-fold increase in production rate. This Best Practices provides more information about sandstone acidizing technology and how it can help improve your sandstone acidizing success rate.

Formation Analysis To perform a successful acidization treatment, operators must know the composition of the formation at the treatment point. The dominant mineral component and temperature of the target formation will determine the most effective formation conditioning system (preflush), HF/HCl treatment blend, and volumes. The presence of potassium feldspars, sodium feldspars, illite, carbonates, and zeolites is a primary concern since these compounds can form or contribute to forming significant matrix-blocking precipitates, such as sodium or potassium fluosilicates and aluminum fluorides, during HF/HCl treatments. Water-sensitive clays also require special consideration because they may swell, obstructing the formation matrix. Precipitates and swelling can be controlled or eliminated with effective treatment planning. HCl-sensitive formations must be identified before treatment so that severe precipitation of sandstone reaction products will not occur. If possible, an X-ray diffraction analysis of a formation core from the target area should be obtained. For wells without core samples, Halliburton’s Spectral Gamma Ray Log procedure can provide an accurate target area mineral analysis for use in treatment planning.

Formation Conditioning Treatment of a well before sandstone acidization can greatly increase the success rate of the stimulation treatment. Formation conditioning design depends on the presence of key minerals. Proper formation conditioning before treatment with HF acids is critical to the success of the stimulation treatment. The flowcharts on Pages 8 and 9 can help you design an effective conditioner for your formation. Table 1 (Page 2) describes the problems that certain minerals commonly found in sandstone formations can cause. Table 2 (Page 3) describes various formation conditioning systems and when they should be used. Effective Sandstone Acidizing

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Table 1—Formation Minerology Mineral Feldspars

Carbonate Illite

Problem Feldspars contain sodium and potassium. The major concern is fluosilicate precipitation. K-Spars cause the most precipitation problems. Carbonate consumes HCl and can cause precipitation of fluosilicates and aluminum from spent acid. Illite causes fines migration problems and is ion-exchanging. It contains potassium, which can cause fluosilicate precipitation from spent acid.

Kaolinite

Kaolinite causes fines migration problems. It disperses in fresh water and causes plugging.

Smectite

Smectite is an ion-exchanging mineral that swells in fresh water.

Mixed-Layer Clay

Chlorite

Mixed layer clay is ion-exchanging and swells in fresh water. It often contains potassium, which can cause fluosilicate precipitation from spent acid. Chlorite is ion-exchanging and unstable in HCl.

Mica

Mica is ion-exchanging and unstable in HCl. It contains potassium, which can cause fluosilicate precipitation from spent acid.

Zeolite

Zeolite is ion-exchanging and unstable in HCl. It often contains sodium, which can cause fluosilicate precipitation from spent acid.

Clays Ion exchange on clays was previously thought to be of minor consequence. However, recent work has shown that the impact of ion exchange can be dramatic for brines undergoing deep matrix invasion in sandstone with clays having a significant ion-exchange capacity. When ion exchange occurs, the cations naturally present on the surfaces of the clays are replaced or exchanged with ions from the invading brine. This transformed brine must also maintain compatibility with the formation.

NH4Cl Recent research involving 3-ft columns packed with sand and clay has demonstrated the importance of brine compatibility both before and after ion exchange. For example, when 3% CLAYFIX (NH4Cl) flows across an ion-exchanging clay, the solution becomes 3.3% sodium chloride brine. This initial concentration may be sufficient before ion exchange. However, the concentration of salt after exchange is not high enough to prevent swelling of watersensitive clays (smectite or mixed-layer clay). The result is the loss of matrix permeability. The most effective brine for sandstone acidizing is NH4Cl. CLAYFIX 5 Conditioner provides sufficient ion exchange and maintains enough salt concentration to prevent clay swelling before and after ion exchange.

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Table 2—Formation Conditioning Systems Fluid System

When to Use

Mud Cleanout Mud-Flush

Removes whole water-based mud losses

N-Ver-Sperse

Removes whole oil-based mud losses

Wellbore Conditioning Paragon or other organic solvents

Removes asphaltene/paraffin deposits, heavy oils, pipe dope

HCl for pickling

Removes iron scales and prevent them from entering the formation

Oil Well Conditioning Gidley's CO2 Conditioner

Helps prevent emulsion problems and terminal upsets; improves acid penetration into oil zones

Matrix Conditioning CLAYFIX 5 Conditioner 5 to 15% HCl

Helps condition high ion-exchanging clays

CLAY-SAFE 5 Conditioner

Helps condition carbonate removal, ion exchange for HCl-sensitive minerology

CLAY-SAFE H Conditioner

Helps condition HCl-sensitive minerology, but requires removal of polymer damage (K-Max, HEC, etc…) or high carbonate levels

Helps condition carbonate removal, ion exchanging, remove polymer damage

HCl-Sensitivity and Clay Instability Ratings Many formations are “HCl-sensitive;” formation minerals decompose when contacted by HCl. During this process, metal ions such as Fe, Al, Ca, and Mg, are dissolved from the mineral, leaving an insoluble silica gel mass that can be extremely damaging. HCl-sensitive minerals include zeolites and chlorite. However, research has shown than all clays have a temperature above which they are unstable. An instability rating for clays at various temperatures has been determined to address this problem. For example, if a formation contains 5 to 10% illite with a BHST of 225ºF, it is considered HCl-sensitive. Figure 1 below shows clay instability rating curves for various common clays.

100

Ch lor Illit ite e Sm ect i Kao te lini te

ime alc

50

An

Instability Rating

75

25

Feldspar

0 50

100

150

200

250

300

350

Temperature (oF)

Figure 1—Clay instability rating of various clays at different temperatures

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When formation minerals have an instability rating of 0 to 25, use HCl preflushes and HCl-HF fluids. At high instability ratings of 75 to 100, use only organic, acid-based systems. This consists of the organic acid-based CLAY-SAFE conditioners followed by an organic-HF system, Volcanic Acid System. If the stability rating is from 25 to 75, use CLAY-SAFE conditioners. The HF stage can either be an HCl-based fluid or the Volcanic Acid System. A very successful recommendation has been the use of CLAY-SAFE conditioners followed by the appropriate HCl-HF fluid system. HCl alone can be very damaging in these types of formations, but HCl in the presence of HF is not. The HF prevents massive silica deposition, which minimizes the effect of the clays’ HCl-sensitivity. As the instability rating exceeds 50, use the Volcanic Acid Systems. Many cases exist in which HCl-based fluids worked well, and others where completely organic acid systems provided excellent results. Historical performance of treatments in the area and personal experience can help you choose the appropriate fluid.

Acetic Acid Despite the sensitivity of clays to HCl, they are stable in acetic acid and fairly stable in formic acid. Unfortunately, both of these acids are similar to fresh water in the presence of water-sensitive clays. Substituting acetic acid (MSA) for CLAYFIX is not a good alternative, since MSA does not exchange ions with the clays or prevent clay swelling. MSA is not an equivalent substitute for HCl because it does not dissolve iron scales and is slow to dissolve carbonates. However, use of CLAY-SAFE conditioners should provide sufficient ion exchange to help 1) prevent precipitates in the HF/HCl process, 2) control clay swelling, and 3) stabilize the clay to sandstone acidization.

Cation-Exchanging Minerals (CEMs) If the CEMs (stilbite, bentonite, zeolites, smectite, illite, mixed layer clays, and chlorite) exceed 15%, use CLAYFIX 5 ahead of the preflush containing CLAYSAFE conditioners. This combination of preflushes will provide enough ion exchange to help prevent clay swelling.

Carbonates Sandstone formations containing greater than 5% carbonates are prone to matrix precipitation of complex aluminum fluorides as spent HF flows across the carbonates. The solution to this problem requires 1) deep removal of the carbonate with large preflushes of HCl or 2) the use of an additive that prevents precipitation. For example, 50 gal/ft of 15% HCl preflush in a sandstone containing only 5% calcite will remove the calcite in a radius of about 2 ft from the wellbore. If spent HF follows, aluminum fluoride precipitation will begin 2 ft from the wellbore. Since 150 gal/ft of spent HF would penetrate about 5 ft from the wellbore in a 20% porosity rock, several feet of matrix would be subject to precipitation and plugging. To remove the carbonate to a distance of 5 ft, 300 gal/ft of 15% HCl preflush would be required.

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Laboratory tests and field studies have revealed that the addition of ALCHEK in the sandstone acidizing treatment can help prevent precipitation of aluminum fluorides as spent HF flows across carbonate. Preventing precipitation ensures that the formation retains the full permeability improvement potential of the sandstone acidizing system.

Matrix Conditioning Volume To provide adequate ion exchange, remove carbonates, and optimize sandstone acidizing, the volume of matrix conditioner should be equal to or greater than the volume of the sandstone acid used in the treatment. Many fields contain more than 20 to 40% of total ion-exchanging clays. For these fields, the preflush fluid volume needs to be sufficient to complete the ion exchange before the spent HF flows across the clays. Fields that contain less than 30% of ion-exchanging clays should be conditioned with about 100 gal/ft of HCl, 100 gal/ft of CLAYFIX 5, or a 50/50 combination of both. Fields that contain more than 30% of ion-exchanging clays should be treated with about 150 gal/ft of matrix conditioners.

Gidley’s CO2 Conditioner Carbon dioxide preflushes have successfully prevented terminal upsets after sandstone acidizing treatments and have improved the HF treatment response. One operating company’s study revealed that oil-wet particulates (colloidal silica and fines) stabilized the terminal emulsions. These particles were precipitated from HF acid reacting with the formation in the presence of hydrocarbons, such as crude oil and xylene. The solution is in Gidley’s CO2 Conditioner, a Halliburtonexclusive process that removes the hydrocarbons from the near-wellbore area. The carbon dioxide treatment uses 100 to 200 gal/ft of CO 2 under miscible conditions to displace the oil away from the matrix in the near-wellbore area. Displacing the hydrocarbons allows better HF invasion of the matrix and prevents emulsions from forming. The CO2 can also be used throughout the acid stages to provide enhanced energy for cleanup. Some oils form asphaltene precipitation easily and other oils have minimal miscibility with CO2 under reservoir conditions. Both of these conditions can be at least partially eliminated with a xylene preflush ahead of the Gidley’s CO2 Conditioner.

Additional Information Brines that remain compatible both before and after ion exchange include 5% NH4Cl, 7% KCl, 5% CaCl2, and 6% NaCl. These brines are sufficient to complete the ion exchange in deep-matrix invasion and prevent clay-swelling. They should be considered for a variety of operations including gravel-packing, sandstone acidizing treatments, killing wells, perforating, and any other operations where deep-matrix invasion is expected. In fact, practices such as killing a well with seawater alone might be a source of deep-matrix damage.

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Treatment The correct ratio of HCl to HF in an acid blend is selected based on the minerals present in the target area of the well. The flowchart on Page 9 is designed to help you determine the best acid blend for your needs. Table 3 describes the available sandstone acid systems. Table 3—Sandstone Acidizing Systems Fluid Name

Advantages

Sandstone Completion™ Acid This acid formulation is the fluid of choice when the mineralogy is unknown. It offers maximum dissolving power with minimum secondary precipitation and prevents aluminum precipitation. Fines Control™ Acid

This formulation is a retarded system that removes deep damage caused by fines and swelling clays. It also helps prevent fines migration.

K-Spar™ Acid

This acid is compatible with formations high in feldspars and illite. It also helps prevent fines migration.

Volcanic™ Acid

This organic acid system is compatible with HCl-sensitive minerals. It can also be used used in high temperature applications.

Silica Scale™ Acid

This acid uses a high HF concentration to remove silica scale from geothermal wells.

HF Reactions The three stages of matrix reactions that can affect your choice of acid systems are described in the following paragraphs. Primary Stage The primary HF reaction removes matrix damage and improves permeability. Live HF reacts with sand, feldspars, and clays. The reaction results primarily in silicon fluorides with some aluminum fluorides. The HF acid provides the greatest dissolving power during this phase while only a small amount of HCl is consumed. The primary stage is the stage that removes skin damage. Secondary Stage During the secondary reaction, the silicon fluorides react with the clay and feldspar. The reaction releases a large amount of aluminum into the solution, consumes a large amount of HCl, and forms silicon precipitates. Only the aluminum fluorides are present at the end of the secondary reaction; the silicon fluorides have vanished. The critical part of the reaction is to control how the silicon precipitates. Researchers have discovered that precipitation of silicon as silica gel is not a significant problem in flow tests conducted below 250°F. Silica gel precipitation is not a problem if the fluid is in flow. If live HF is shut-in across the perforations, severe and permanent damage to the matrix permeability can result from the silica gel precipitates. If the temperature is above 100°F, this precipitation cannot be prevented.

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The precipitation of silicon as silicon fluorides can be very damaging. This precipitation of silicon can be prevented with improved fluid design. In one case in Indonesia, Silica Scale™ Acid was used on a potassium-dominant feldspar formation at 200°F. Based on previous research, silicon fluoride precipitates would likely form. An ammonium chloride overflush was used, and the treatment pressure was increased. When an HCl overflush was used in other treatments, the treatment pressure decreased. The ammonium chloride overflush increased the treatment pressure response because the HF was no longer active, and the fluosilicate precipitates were plugging the matrix. Pressure did not increase with the HCl overflush because the HCl redissolved the precipitate. The dissolved precipitate continued to react until the silicon fluorides were no longer present, thereby preventing the pressure increase. Based on these observations, a pressure increase from an ammonium chloride overflush indicates a potential incompatibility between the acid and the formation mineralogy. The success rate of sandstone acidizing depends on how effectively the acid blend prevents silicon fluoride precipitation. Tertiary Stage During the tertiary reaction, the aluminum fluorides react with either clay or carbonates until all remaining acid is consumed. The resulting solution contains spent acid and complex aluminum fluorides. If a brine source is available to raise the pH and mix with the aluminum, the aluminum will precipitate with small amounts of silica gel to form “alumino silicate scale.” Although the addition of 3 to 5% acetic acid and ALCHEK in the treatment process can greatly reduce or eliminate alumino silicate scale in the wellbore, only ALCHEK can effectively prevent alumino silicate scale deep in the matrix.

HCl/HF Ratios The ratio of Hcl to HF depends on the dominant minerals and temperature in the formation. Tests were conducted on sodium feldspars, potassium feldspars, and illite-dominant formations to determine the best acid blend to prevent sodium and potassium fluosilicate precipitation at varying temperatures. The results are listed in Tables 4 through 6 (Page 10). The optimal ratio of HCl to HF is 9:1; the minimum ratio is 6:1. Research and field results have shown Fines Control Acid™ (retarded HF) provides excellent compatibility with formation minerals.

Acid Volumes What are the guidelines for choosing lower HF volumes? Although 1.5% HF has half the dissolving power of 3% HF, doubling the volume of 1.5% HF will not produce the same results, because lower HF concentrations react much more slowly with sand. This slower reaction allows the HF to use more of its dissolving power on such targeted damage sources as clays and feldspars while using less dissolving power on sand. Table 7 shows the different HF concentrations and volumes that will give the same performance.

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Start

Are HCI-sensitive clays or zeolites present?

Yes

No

Condition with CLAY-SAFE 5

Condition with HCI Are CECs >15%?

No

Yes

Yes

Are CECs freshwatersensitive?

No

Condition with CLAYFIX 5 ahead of CLAY-SAFE 5 Is carbonate >5%?

Yes

Conditioning acid volume = HF treatment volume (Include ALCHEK¨ in the selected acid treatment)

No

Conditioning acid volume = 75% of HF treatment volume

*Recent experimental results indicate that ALCHECK can successfully prevent or reduce the formation of aluminum precipitates during HF treatments in which carbonates are present.

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Start

Feldspar Clays Zeolites

Present?

No

HCIsensitive?

Yes Present?

Go to Clays

Yes

Treat according to temperature below

K present? (illite) Yes

250 200 175

Treat with VolcanicTM Acid

No

HF Blend Sandstone CompletionTM K-SparTM

Fines ControlTM Acid can be used at any temperature

Record blend; go to Final Blend

Record blend; go to Zeolites

Final Blend Choose most compatible or weakest HF blend from all applicable categories

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Organic-HF Acid Acetic HF and formic HF fluids often are used to remove skin damage and increase production in wells that cannot tolerate HCl-based fluids. However, these fluids can produce severe secondary precipitation of HF reaction products and are not recommended. New organic HF acid systems can replace the use of acetic HF and formic HF fluids in HCl-sensitive formations. An organic acid, such as ALCHEK, is blended with the HF acid to prevent the secondary precipitation with HCl-sensitive minerals, such as chlorite, zeolites, and clays. Volcanic Acid, Halliburton’s new organic-HF acidizing blend, is also suited for use in high-temperature formations and helps prevent HCl-induced sludging. It incorporates NH4Cl to prevent swelling of water-sensitive clays and a penetrating agent to help acid contact the damage. Volcanic Acid II is based on ALCHEK as the organic acid.

Table 4—Application to Sodium Feldspar Temp °F > 175 < 175

HF Blend Sandstone Completion Acid K-Spar Acid

Table 5—Application to Potassium Feldspar Temp °F > 250 > 200

HF Blend Sandstone Completion Acid K-Spar Acid

Table 6—Application to Illite Temp °F > 200 > 125

HF Blend Sandstone Completion Acid K-Spar Acid

Table 7—HF Acid Volume Guidelines HF Concentration 3% 1.50% 1% Retarded HF

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Volume gal/ft 100 150 200 200

BEST PRACTICES

Avoiding Problems ALCHEK If carbonates are present in the formation, the addition of ALCHEK in the HCl/HF treatment blend successfully prevents or reduces the formation of aluminum precipitates. Alumino-silicate is an amorphous scale containing both aluminum and silicon. The scale forms when spent HF has lost all acid, the silicon fluorides have completely reacted to place a large amount of aluminum into solution, and a brine source is available to raise the pH. ALCHEK is more effective than acetic acid at preventing aluminum scaling and aluminum precipitation in the formation. ALCHEK is used in Sandstone Completion Acid, Volcanic Acid II, and in other acid systems when the formation consists of 5% or more carbonates.

Clean Water The use of clean water, rather than saltwater or potassium chloride water, will ensure that the ammonium chloride is at its full potential to perform ion exchange with the formation instead of the sodium or potassium in the contaminated water. If contaminated water is used, the concentration of ammonium chloride may be insufficient to prevent matrix plugging from fluosilicate precipitation or clay swelling.

Brine Compatibility Recent studies at Halliburton Energy Services have revealed that heavy completion brines are incompatible with most formation waters. In most cases, the combination of heavy brines and formation water results in salt precipitation. Formation zones with heavy brine losses from the wellbore should be preflushed with large volumes of CLAYFIX 5 Conditioner. The CLAYFIX 5 Conditioner will dissolve the salt and increase the effectiveness of the acid treatment. Failure to use CLAYFIX 5 Conditioner will allow salt to precipitate in the matrix when the HCl preflush contacts the heavy brine.

Water-Based Mud Loss Wells having significant mud loss across the producing interval require special attention. If the mud lost is a normal water-based bentonite mud, use Mud-Flush to thin the mud and flow it back. Each stage should be about half the volume of the mud lost and should be pumped and returned to the surface. For example, if the zone took 100 bbl of mud, a two-stage treatment of Mud-Flush should be used. Continue to pump subsequent stages until the returns are fairly clean.

Oil-Based Mud Loss Every producing interval drilled with an oil-based mud should be treated with N-Ver-Sperse to remove oil-wet mud solids and remove the leaked-off oil carrier. The oil-wet mud solids will not be easily attacked by HF because of the oil surrounding them. The oil leak off can cause severe emulsion problems. If whole mud has been lost, contact with acid will cause a semipermanent substance

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similar to peanut butter to form. One recent case involved a well with two unsuccessful HF treatments. An N-Ver-Sperse mud removal treatment brought the well in at close to the tubing-limited production rate.

Scales in Wells For a successful HF stimulation, mechanically or chemically clean the wellbore before treatment. Cleaning the wellbore ensures that the treatment acid will react with the formation instead of the wellbore contents. Cleaning also prevents scale in the wellbore from being pushed down into the formation.

Tubular Metallurgy Inhibitors Use the Halliburton Chemical Stimulation manual to choose the correct metallurgy inhibitor for your location. The inhibitor and stimulation chemicals should be compatible to achieve maximum acid effectiveness.

Other Sandstone Acidizing References

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1.

Gdanski, R.D.: “AlCl3 Retards HF Acid for More Efficient Stimulations,” Oil & Gas J. (Oct. 1985) 111-115.

2.

Gdanski, R.D. and Peavy, M.A.: “Well Returns Analysis Causes ReEvaluation of HCl Theories,” paper SPE 14825 presented at the 1986 SPE Symposium on Formation Damage Control, Lafayette, Feb. 26-27.

3.

Almond, S.W., Brady, J.L., and Underdown, D.R.: “Return Fluid Analysis from the Sadlerochit Formation, Prudhoe Bay, Alaska: Field Study - Part I,” paper SPE 18223 presented at the 1988 SPE Annual Technical Conference and Exhibition, Houston, Oct. 2-5.

4.

Shuchart, C.E. and Ali, S.A.: “Identification of Aluminum Scale with the Aid of Synthetically Produced Basic Aluminum Fluoride Complexes,” SPEP& F (Nov. 1993) 291-296.

5.

Gdanski, R.D.: “Fluosilicate Solubilities Impact HF Acid Compositions,” paper SPE 27404 presented at the 1994 SPE Symposium on Formation Damage Control, Lafayette, Feb. 7-10.

6.

Shuchart, C.E. and Buster, D.C.: “Determination of the Chemistry of HF Acidizing with the Use of 19F NMR Spectroscopy,” paper SPE 28975 presented at the 1995 SPE International Symposium on Oilfield Chemistry, San Antonio, Feb. 14-17.

7.

Shuchart, C.E.: “HF Acidizing Returns Analyses Provide Understanding HF Reactions,” paper SPE 30099 presented at the 1995 SPE European Formation Damage Control Symposium, The Hague, The Netherlands, May 15-16.

8.

Gdanski, R.D.: “Fractional Pore Volume Acidizing Flow Experiments,” paper SPE 30100 presented at the 1995 SPE European Formation Damage Control Symposium, The Hague, The Netherlands, May 15-16. BEST PRACTICES

9.

Gdanski, R.D. and Shuchart, C.E.: “Newly Discovered Equilibrium Control HF Stoichiometry,” paper SPE 30456 presented at the 1995 SPE Annual Technical Conference and Exhibition, Dallas, Oct. 22-25.

10.

Gdanski, R.D.: “Kinetics of the Tertiary Reaction of HF on AluminoSilicates,” paper SPE 31076 presented at the 1996 SPE Formation Damage Symposium, Lafayette, Feb. 14-15.

11.

Guichard, J.A. III, Allison, D., Gdanski, R.D., and Ghalambor, A.: “Modified Retarded Stimulation Treatments Improve Production From Wilcox Reservoirs,” paper SPE 31139 presented at the 1996 SPE Formation Damage Symposium, Lafayette, Feb. 14-15.

12.

Shuchart, C.E., Gdanski, R.D.: “Improved Success in Acid Stimulations with a New Organic-HF System.” SPE 36907, European Petroleum Conference, Milan, Italy, October 22-24, 1996.

13.

Gdanski, R.D.: “Kinetics of the Secondary Reaction of HF on AluminoSilicates,” SPE 37214, 1997 SPE International Symposium on Oilfield Chemistry, Houston, February 18-21, 1997.

14.

Shuchart, C.E.: “Chemical Study of Organic-HF Blends Leads to Improved Fluids,” SPE 37281, 1997 SPE International Symposium on Oilfield Chemistry, Houston, February 18-21, 1997.

15.

Gdanski, R.D.: “Kinetics of the Primary Reaction of HF on AluminoSilicates,” SPE 37459, 1997 SPE Production Operations Symposium, Oklahoma City, March 9-11, 1997.

Notice: This publication is based on sound engineering practices, but because of variable well conditions and other information that must be relied upon, Halliburton makes no warranty, express or implied, as to the accuracy of the data or of any calculations or opinions expressed herein. Halliburton shall not be liable for any loss or damage, whether due to negligence or otherwise, arising out of or in connection with such data, calculations, or opinions. Effective Sandstone Acidizing

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Notes

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Notes

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