SPE 102468 Lessons Learned and Guidelines for Matrix Acidizing With Viscoelastic Surfactant Diversio

Copyright 2006, Society of Petroleum EngineersThis paper was prepared for presentation at the 2006 SPE Annual Technical Conference and Exhibition held in San Antonio, Texas, U.S.A., 24–27 September 2006.This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers 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, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.AbstractTo conventionally drill, complete and produce horizontal and multilateral wells with zero skin is not an easy undertaking. Much attention has been given to “best oil field practices” in both drilling and production processes, but the reality is that formation damage will often have to be addressed sometime during the life time of the well.Formation damage due to drilling and scale formation is common problem in carbonate reservoirs that can be re-mediated using chemical means. The success of any treatment however, requires a complete understanding of the problem and a solution that will address the majority of the damage. The solution evolves with time and experience. Extended reach intervals with variable permeability complicate the process. Reservoir and fluid characteristics, cleanup fluid chemistry, and operational considerations must always be considered.The acidizing experience and an improved understanding of how to effectively treat long and heterogeneous intervals in carbonate formations is rapidly evolving in Saudi Arabia. Water injectors, oil producers and wastewater disposal wells have been treated and are reviewed in this study. These wells have different configurations including: vertical, horizontal, extended reach, and multilateral with open hole and cased completions. Several acid placement and diversion techniques have been applied and a specialized treatment package was developed based on the latest coiled tubing and chemical diversion technologies. Laboratory studies, lessons learned and specific design guidelines from both successful and less than expected well treatments are highlighted in this work.IntroductionVarious materials and methods have been applied to enhance acid diversion across long treatment intervals. Each technique has some merits, and the basic goal of all is to temporarilyshut-off higher permeability sections in order to force the stimulation fluids into the lower permeability sections. As with many situations however, excess can cause undesirable results. Solid bridging materials have successfully been used in acid wash applications, however they can be difficult to handle operationally, and over-treatment can prematurely cause plugging when not desired. Particulate-based systems can only be considered to provide near wellbore diversion. In “bullhead” treatments, diversion systems are generally effective for relatively small intervals. The main point is that leak-off into lower sections must be achievable to enable the acid to flow into them. Otherwise, the acid will only treat the upper sections, typically just below the last casing shoe. The acid dissolution rate must also be considered. For example, regular hydrochloric acid will react very rapidly with carbonate formations, especially at high bottom hole temperatures; spending itself on the formation before reaching the desired placement. Emulsified acid has a dissolution rate nearly 15 times slower than the regular acid. This means the acid can travel farther along a wellbore and penetrate deeper into the formation before spending.1,2 Coiled tubing is the ideal placement method for matrix acidizing of long, horizontal, open hole intervals in carbonate formations. Pinpoint placement of acid is possible, and the leak-off rate is very low. Basically, the acid will react in the vicinity, relative to the position of the end of the coiled tubing. Another benefit of the continuous pipe is the ability to pull-out of hole without the need of breaking joints on surface (as in the case of drill pipe). The closed system is also better suited for well control when positive annular wellhead pressure is expected at the surface.Polymer-based systems are easier to handle than particulates and diversion is achieved via the formation’s natural resistance to viscous flow.3 There is a tendency in the industry however, to overtreat formations with polymers, whether as “Hi Vis” LCM pills while drilling or as a diversion pill in an stimulation treatment. Later on, the production engineer has the daunting task of trying to make a well that is severely damaged with a deep penetrating gel.To overcome potential problems associated with other diverters, a surfactant-based system was introduced. Previous studies have highlighted the unique properties and applications of viscoelastic surfactants.4-6 The present study is intended to highlight the findings from the lab, field and to provide somedesign guidelines of various matrix stimulation strategiesSPE 102468Lessons Learned and Guidelines for Matrix Acidizing W ith Viscoelastic Surfactant Diversion in Carbonate FormationsH.A. Nasr-El-Din, SPE, Saudi Aramco, and J.B. Chesson, SPE, K.E. Cawiezel, SPE, and C.S. Devine, SPE, BJ Services Co .2 SPE102468being applied in Saudi Arabia. Most treatments (more than 95%) have been successful, but there were three cases where the results fell below expectations.The objectives of this study are to: (1) Assess the performance of this new viscoelastic surfactant based-acids on field results, (2) Develop guidelines and best practices for using this surfactant in the field, and (3) Design remedial treatments that can restore the performance of wells damaged from improper use of this surfactant.Laboratory FindingsViscoelastic surfactants have recently become a popular additive for diversion pills, based on their polymer-free chemistry. Various formulations, including foam, have been successfully applied in matrix acid stimulation treatments. Viscoelastic fluid properties vary over a pH range during acid spending on the formation and when foamed, determination of bottomhole properties is further complicated.Extensive laboratory testing has been done to better understand how viscoelastic surfactants work in the field. The diversion mechanism is similar to that of a gel, viscous fluid banking.4 Rheological properties depend on shear rate and are affected by parameters such as surfactant chemistry, concentration, temperature, acid concentration, reaction product, formation fluids, and corrosion inhibitors.5 These surfactants can generate high viscosity at low shear rates, which, like polymers, can impede cleanup from the formation, if too much radial zone is invaded. Hydrocarbons (diesel, oil, or condensate) and mutual solvents (ethylene glycol monobutly ether) act as breakers when they come in contact with viscoelastic surfactants.7,8Laboratory testing has proven that a lower concentration of viscoelastic surfactant can provide the required viscosity to achieve effective diversion. A lower concentration of viscoelastic surfactant will facilitate cleanup at lower bottomhole temperatures without a breaker and obviously make it a more cost effective material.Nature and MechanismThe viscoelastic surfactant used in the present work is amphoteric from the amine oxide family of surfactants. The surfactant molecules align themselves and form rod-shaped micelles as the acid spends. As hydrochloric acid reacts with carbonate minerals (calcite and dolomite), the pH rises and the concentrations of calcium chloride and magnesium chloride will increase. The increase in pH and the presence of divalent cations cause the surfactant molecules to form long rod-like micelles. The entanglement of these micelles results in a 3-D structure, which produces substantial viscosity to the spent acid, especially at low shear rates.7,8Rheological PropertiesThe rheological properties of viscoelastic surfactants are a complex function of surfactant type, concentration, additives, salinity, temperature, and shear rate.5 There are various surfactants commercially available that can be used with acid, however each material should be evaluated individually to determine how each parameter will affect its rheological properties.Fig. 1 illustrates the effect of acid concentration on the apparent viscosity of live acids whereby the rheological properties are affected by the initial acid concentration. This particular surfactant is generally mixed and pumped in a 20 wt% HCl to avoid the viscosity spike that occurs at a concentration of 10-15 wt%. This trend may happen at a different acid concentration for other surfactant chemistries.Fig. 2 illustrates the effect of temperature on the apparent viscosity of partially spent acids in a range of pH = 1.2 to 4. It should be noted there is no significant effect on viscosity at pH values greater than 4.It is recommended to focus on the spent fluid viscosity when designing a treatment. This will allow the engineer to estimate the depth of penetration or the volume required for diversion across specific zones. The viscosity development at various pH values helps exemplify the fluid’s behavior while pumping. Ultimately, the spending fluid will find a zone to leakoff into and become a viscous, static fluid bank that penetrates some distance into the formation. The high viscosity of the spent fluid provides excellent leakoff control for the remainder of the treatment, but it is also important to keep post treatment cleanup in mind, especially in lower permeability zones. The high viscosity of this fluid in the static state means that diversion can generally be achieved with small volumes.Fig. 3 illustrates the effect of the shear rate on the apparent viscosity of a 4 vol% viscoelastic surfactant-based fluid. A power-law relationship can be seen whereby the viscosity decreases with the shear rate, i.e., shear thinning behavior. This behavior is important in minimizing friction losses during placement, especially through small ID tubulars such as coiled tubing. The shear rate will decrease significantly as the fluid enters the wellbore. The injected acid will continue to gain viscosity as it spends and achieve a maximum value as the formation’s natural resistance causes the fluid to approach a static state.Fig. 4 illustrates the effect of temperature on the apparent viscosity of various surfactant concentrations. At temperatures greater than 250°F the apparent viscosity begins breaking down without stabilizers added. This can be achieved with the addition of salts and/or methanol. This information is important to consider for stability during the treatment, and for post treatment cleanup.A previous study found viscoelastic surfactant to be an effective foaming additive in fresh water and heavy brines.4 Fig. 5 compares the viscosity of a 70 vol% foam with 1.5-3 vol% viscoelastic surfactant at 250°F vs. the base fluid. The apparent viscosities of the foamed surfactants is about 10-fold higher than the non-foamed solutions. More recent parallel coreflow testing has established that effective foam diversion can be achieved with surfactant concentrations as low as 1.5 vol%.In parallel core flow tests with large permeability contrasts, infinite permeability was achieved for each plug. Acid break- through occurred first for the lower permeable cores, indicating that the flow was diverted from the higher permeability core to the lower permeability cores.4 Viscoelastic surfactant-based foams have been successfully used as diversion pills between acid stages to increase the performance of water injection wells. More recent parallel coreflow testing has established that effective foam diversionSPE 102468 3can be achieved with surfactant concentrations as low as 1.5 vol%.Chemical IncompatibilityField acids are prone to pick up iron from the field mixing equipment and through the tubulars, even when pickling is done; thus it was decided to determine the effect of iron at lower concentrations on the surfactant-based acid. If there are adverse effects, then perhaps the addition of a chelating or reducing agent could help maintain fluid viscosity. The results of the Fann 50 testing in Fig. 6, indicate that ferric iron concentrations up to 500 ppm do not adversely affect the apparent viscosity of the surfactant-based acid. However, a high ferric iron concentration of 5,000 ppm will reduce the fluid viscosity at temperatures greater than 125°F. The addition of a reducing agent to the fluid with 5,000 ppm ferric iron did not notably eliminate the effect of iron.As with any acid treatment, every effort should be made to minimize the iron content introduced into the live acid. Quality control of surfactant-based acids should include measuring total iron. Higher iron concentrations can adversely affect the performance of these acids, especially in sour environments.Some corrosion inhibitors contain solvents which are detrimental to the micelle structure of viscoelastic surfactants and apparent viscosity is adversely affected at higher inhibitor concentrations. Fig. 7 shows that the surfactant in this study is sensitive to a particular corrosion inhibitor loading above 4 gpt. This loading will actually provide adequate protection time for the cases examined in the present study. The bottom hole temperatures for most wells pumped thus far are in the 180-225°F range.In general, mutual solvents and hydrocarbons will affect the shape and structure of viscoelastic micelles and cause dramatic reduction in viscosity.7,8 These chemicals are considered as breakers and will reduce viscosity when they come in contact with the spent acid.5Coreflood FindingsLaboratory testing was initiated to optimize the concentration of viscoelastic surfactant that should be added to 20 wt% hydrochloric acid systems.Core testing was performed on carbonate cores to simulate damage and clean up of the viscoelastic surfactant in 20 wt% HCl with 4 gpt corrosion inhibitor. A fractional pore volume was used (0.6 pore volume). Three tests were performed, with surfactant concentrations of 3, 4, and 6 vol%. The core study was initiated to provide flow test results for these three systems at a temperature of 200ºF. The fluids included: 2 wt% KCl brine; 20 wt% HCl with 4 gpt corrosion inhibitor, containing either 3, 4, or 6 vol% of the surfactant; and a cleanup fluid consisting 5 vol% mutual solvent. Approximately 400 psi backpressure was used during acid injection and 1,500 psi confining pressure was applied. Pre- and post-treatment liquid flow was conducted at constant rate while accurately measuring flow rates with a liquid mass flowmeter. Pressures were accurately monitored with electronic differential pressure transducers. The pressure drop across the core and the flow rate data were used to calculate permeability. The flow procedure included the following steps: Inject 2 wt% KCl brine in the production direction to steady state pressure drop across the core. Inject 0.6 pore volume of the acid in the reverse (treatment) direction. Flow KCl brine in the production direction to determine retained permeability. If damage is indicated, inject the cleanup fluid (3 pore volumes). Flow was then re-established in the production direction to steady state pressure drop across the core.The results of flow testing in Table 1 indicate that 3 and 4 vol% surfactant concentrations are optimal for fractional pore volume testing. These cores required no cleanup. Cores treated with acid containing 5-6 vol% surfactant required a 5 vol% mutual solvent treatment to remediate the damage that resulted from using high surfactant concentrations. A 5 to 10 vol% mutual solvent solution in brine is also an effective breaker fluid. Diesel is typically used in oil producers to minimize the risk of creating emulsions.Design GuidelinesThere are several different matrix acid scenarios pumped depending on well configuration and damage mechanism. The wells are either injectors or producers and generally are completed vertical or horizontal open hole. The formation is limestone and dolomite. The acid treatments are required to remove the damage caused by drilling, completion or workover fluids and precipitation of solids.6 A retarded acid is commonly used for the stimulation of both water and oil wells in carbonate reservoirs. This system uses an emulsifier to form a stable oil external/acid internal emulsion. A 30 vol% diesel phase and a 70 vol% acid internal phase are mixed to form an emulsion. The oil external layer that surrounds the acid droplets basically shields the acid from the formation, minimizing near wellbore dissolution and allowing the acid to penetrate deeper into the formation before spending.1,2 Emulsified acid has inherent viscosity which aids in formation diversion.9An additional diversion fluid is required for high permeability contrasts that often occur in long open hole intervals. Surfactant-based acids and foam diversion have been successfully applied for treating both injectors and producers. As previously mentioned, viscoelastic surfactants are not compatible with hydrocarbon-based fluids, thus a spacer, e.g., an aqueous fluid without mutual solvent, is required to separate surfactant-based fluid from the emulsified acid.A common treatment fluid sequence includes a 20 wt% regular HCl acid ahead of an emulsified acid stage and followed up with a 20 wt% HCl spacer stage and then a 20 wt% surfactant-based acid. The length of the staged intervals has varied from 200 to 1,500 ft.Some treatments have been successfully bullheaded. These acid programs have been designed for vertical or deviated wells with short perforated or open hole intervals which are less than 500 ft. If it is possible to achieve leak-off into the lower sections, then more complete wellbore coverage from the treatment will be achievable; if not, then the upper section will only be treated and a funnel-shaped washout of the wellbore will occur being most severe at the casing shoe. Table 2 gives atypical program designed for high rate matrix treatments with alternating stages of emulsified acid and4 SPE102468diversion stages to achieve maximum wormholing effect.The concern with a relatively small treatment pumped at high rate is with dilution and contamination of the stages with each other and the formation fluid. The time dependent viscosity development of the viscoelastic-acid diverter may also require additional volume to compensate for the higher net pressure and injection rate. Foam diversion stages are often applied to achieve instant maximum viscosity and extend small staged volumes.Most matrix acid treatments of vertical and horizontal open hole wells are pumped through coiled tubing. Fluid stages are sequenced in 250 ft intervals while adjusting pumping and pull-out rate. Table 3 shows an example treatment of a 2,984 ft horizontal producer well. Emulsified acid is used when matrix stimulation is required. The diversion fluid is a 20 wt% HCl with 4 vol% viscoelastic surfactant.Some extended reach injectors were treated with the rig, due to inaccessibility with coiled tubing. Table 4 shows an example treatment for a 7,713 ft open hole section. These wells are completed as a 6-1/8-inch with open hole sections ranging from 5,000-11,000 ft. Treatments were staged sequentially in 1,000-1,500 ft intervals. The treatments are bullheaded through the rig tubing from the top of each staged interval. The acids were displaced into the formation after each stage sequence before pulling up tubing to treat the next interval.Case HistoriesAt the time of writing this paper, more that 60 treatments have been performed using this particular viscoelastic surfactant in Saudi Arabia. The bottom hole temperature has ranged from 180-225°F, and the true vertical depth has been in the range of 7,000-8,000 ft. Open hole intervals up to 11,000 ft have been treated successfully with this system. Three case histories are presented below to demonstrate what can go wrong when a viscoelastic surfactant is applied improperly.Case History # 1This well is a vertical open hole oil producer that was dead due to water encroachment. The treatment was designed to stimulate the upper 26 ft, Zone 1, with the expectation that the remaining dry oil from the lower Zone 2, could be swept upwards and produced with the upper zone. One other treatment had been performed prior to this well. The treatment for this well was designed based on 20 wt% HCl and the concentration of the viscoelastic surfactant was 6 vol%. This relatively high surfactant concentration was used to ensure there would be sufficient diversion. The treatment consisted of alternating stages of 20 wt% hydrochloric acid, 20 wt% emulsified, 20 wt% hydrochloric acid spacer, and 20 wt% hydrochloric acid 6 vol% viscoelastic surfactant diversion stage. The actual treatment consisted of placing the 1-3/4 inches coiled tubing at 6,278 ft depth and pumping first treatment stage as per stimulation sequence shown in Table 5. Once the first stage reached the end of the tubing, the wing valve was closed and remaining stages were pumped into the formation.The well was flowing prior to the acid treatment, but was unable to flow after the acid treatment. Samples from the treatment indicated that an emulsion had been formed due to the high concentration of viscoelastic surfactant pumped. It appeared that the viscosity of the emulsion was adequate to cause a “gel block” at the reservoir conditions. The emulsion was not difficult to break in the laboratory using diesel and 10 vol% mutual solvent solutions. The recommended treatment to remove the emulsion damage was to squeeze a solution of diesel and 10 vol% mutual solvent into the plugged formation, followed by a nitrogen kickoff. The treatment volume was increased 1.5 times over the stimulation treatment to ensure sufficient penetration of the damaged zone.Case History # 2A vertical cased hole producer perforated 220 ft across the entire carbonate reservoir. The well has a low productivity index (PI) due to the tight permeability (approximate 1 md) of the reservoir and the treatment was designed to penetrate the tight matrix.The treatment consisted of alternating stages of 20 wt% regular hydrochloric acid, 20 wt% emulsified, 20 wt% hydrochloric acid spacer, and 20 wt% hydrochloric acid 6 vol% surfactant diversion stage. The actual treatment consisted of placing the 1-3/4 inches coiled tubing at 6,960 ft depth and pumping first treatment stage as per stimulation sequence shown in Table 6.Once the first stage reached the end of the tubing, the wing valve was closed and the remaining stages were pumped into the formation while reciprocating the coiled tubing across the perforation interval. The well had trouble unloading after the treatment.Post analysis of the well flow back identified a very viscous emulsion. The excessive volume (29 gal/ft) and concentration (60 gpt) of viscoelastic surfactant-based fluid caused plugging in the depleted, low permeability, formation. It was however possible to break the emulsion when it was mixed with diesel and mutual solvent solution. A large volume breaker treatment, consisting of diesel and 10 vol% mutual solvent, was pumped in an attempt to break the viscous emulsion. The fluid was nitrified to extend its radial penetration to 9 ft and also add energy to aid flowback recovery. Nitrogen lifting was also performed in an attempt to kick off the well.Post treatment production jumped to 3,700 bopd and stabilized at 2,000 bopd for 2 months before rapidly declining to 700 bopd. The well was then shut-in as the flowing wellhead pressure was below the system pressure.The sudden drop in the production rate and wellhead pressure suggested that maybe some of the damage had been bypassed in the previous treatment. Perhaps the damage had only been displaced deeper into the formation and then migrated back into the primary flow path. This led to the conclusion that the only way to bypass the damage would be to stimulate past it. A new damage removal procedure was designed to stimulate the formation with a retarded acid (diesel emulsified acid) and foamed diverter stages. The treatment was based on using coiled tubing, and the objective was to open up plugged wormholes and create new ones. A sufficient acid volume was specified to allow the treatment to penetrate 7 ft radially into the formation. It is anticipated that the deep penetrating acid treatment would bypass suspected formation damage remaining from the previous treatment.SPE 102468 5Table 7 highlights the treatment procedure. The emulsified acid is divided into three stages with a spacer acid and two diversion stages to evenly distribute the treatment over the entire perforated interval. Laboratory findings showed that a 65 vol% foam quality could be created with 1.5 vol% viscoelastic surfactant. The idea behind foaming the base fluid is that it will extend its base volume by nearly three times and increase the apparent viscosity by about 10-fold. The lower surfactant concentration and dispersion of the base fluid will facilitate rapid cleanup in the tight low pressure formation.Case History # 3This well is an old offshore producer completed with 4-1/2 inches tubing to the top of perforations from 9,300 - 9,217 ft with net 64 ft in a carbonate reservoir. The well is deviated with a maximum build angle of 35° and PBTD of 9,310 ft (8,530 ft TVD). The reservoir pressure is nearly 3,270 psi and the bottom hole static temperature is 200°F. The well was tested at a rate of 3,500 BOPD with 10 vol% water-cut at a FWHP of 248 psig in March 2004. H2S content is nearly 10 mol%. The well was reported dead in May 2004 and an acid wash was performed in September 2004. The treatment was placed with 1.5 inches coiled tubing and reciprocated across the zones while pumping at about 1.5 bpm. A 10 bbls preflush with 5 vol% mutual solvent was pumped followed by a 10 bbls Hi-Vis pill with 7 vol% surfactant from the top of the perforations ahead of the acid treatment and intended to isolate the wet perforations. 10 bbls of 20 wt% HCl was then divide into two stages and separated by a 10 bbls pill of 20 wt% HCl surfactant-based acid with 4 vol% viscoelastic surfactant. The treatment was displaced into the formation with diesel. The well was not able to cleanup and is presently dead.Two problems were identified. The surfactant loading of 7 vol% in the Hi Vis pill has extreme viscosity in the zone it leaked-off into, probably becoming a permanent plug. To complicate the situation, a quality issue was found in the third party acid which was delivered to location in dirty tanks. Acid samples from the well were analyzed and found to contain approximately 10,000 mg/l total iron. High iron content during acidizing can result in increasing sludging tendency, reduced corrosion inhibitor effectiveness, and precipitation of iron sulfide (in sour environments).Iron can also cause the degradation of the viscosity of the surfactant-based acid, resulting in reducing its diverting effectiveness (Fig. 6).Conclusions - Lessons LearnedThe viscoelastic surfactant discussed in this paper was used in more than 60 treatments in several carbonate reservoirs in Saudi Arabia. The success rate of these treatments exceeded 95%. The following additional conclusions were obtained:1.High surfactant loadings can cause well damageparticularly in low permeability and depleted reservoirs. 2.The damage induced by viscoelastic surfactant-basedfluids can be mitigated using mutual solvent dissolved in diesel or brines.3.Higher corrosion inhibitor loadings can adversely affectthe performance of viscoelastic surfactant used. 4.High iron concentrations will negatively influence theperformance of the viscoelastic surfactant used. Theaddition of a reducing agent did not eliminate this effect.Nomenclaturek w = Brine permeability, mdVES = Viscoelastic SurfactantLCM = Loss Circulation MaterialHi Vis = high viscosityPPM = parts per millionGPF = gallons per FootGPT = gallons per thousand gallonsPPTG = pounds per thousand gallonsmd=millidarcyBOPD = barrels oil per dayTVD = true vertical depth, ftPBTD = plug back total depthFWHP = flowing well head pressureBPM = barrels per minuteBBL = barrelsQuality =percentage of total volume which is gasAcknowledgmentsThe authors would like to thank Saudi Aramco and BJ Services management for the permission to present and publish this paper. Special thanks go to members of the Stimulation R&T Team, Saudi Aramco, for their help the field. Production engineers for all fields discussed in the paper are acknowledged for many useful discussions.References1.Nasr-El-Din, H.A.: “Surfactants Used in AcidStimulation,” In Surfactants, Fundamentals andApplications in the Petroleum Industry, L.L.Schramm (Editor), Chapter 9, Cambridge University,329-364, 2000.2.Nasr-El-Din, H.A., Al-Anazi, H.A. and Mohamed,S.K.: “Stimulation of Water Disposal Wells UsingAcid-in-Diesel Emulsions - Field Application”,SPEPF, 15 (August, 2000) 176-182.3.Economides, M.J., Hill, A.D., and Ehlig-Economides, C.: Petroleum Production Systems,Prentice Hall PTR, New Jersey (1994) 386.4.Nasr-El-Din, H.A., Chesson, J.B., Cawiezel, K., andDevine, C.S.: “Investigation and Field Evaluation ofFoamed Viscoelastic Surfactant Diversion FluidApplied During Coiled-Tubing Matrix-AcidTreatment,” paper SPE 99651 presented at the 2006SPE/ICoTA Coiled Tubing and Well InterventionConference and Exhibition held in The Woodlands,TX, 4-5 April.5.Nasr-El-Din, H.A., Arnaout, I.H., Chesson, J.B. andCawiezel, K.: “Novel Technique for Improved CTAccess and Stimulation in an Extended-Reach Well,”paper SPE 94044 presented at the 2005 SPE/ICoTACoiled Tubing Conference and Exhibition held inThe Woodlands, TX, 12 – 13 April.6.Chatriwala, S.A., Rufaie, Y., Nasr-El-Din, H.A.,Altameimi, Y., and Cawiezel, K.: “A Case Study of aSuccessful Matrix Acid Stimulation Treatment in。