HydrojIuotic-hydrochloric acid mixtures have heen successfully used to stimulate sandstone reservoirs for a number of years. Hydrofluotic acid (HF) has a specific reactivity with silica which makes it more efleclive than HC1 jor use in sandstone. Kinetics of the reactions of HF have been studied to determine the related effects of reservoir composition, temperat::m, acid concentration and pressure on the spending ra~e o~HF. Secondary eflects from by-product formation are noted and described, Predictions are made concerning the improvement in productivity resulting from HF treatment of skin damage.The kinetic order of HF reaction in sandstone was experimentally determined to be first order, i.e., the reaction rate is proportional to concentration. HF reacts faster on calcite than on clay, which, in turn, is faster tiran the reaction rate of HF on sand. Static conditions, retard the HF reaction rate. As HF is forced into cores, there is a temporary reduction as a function of flow rate atrd acid concentration,Extensive deposition of calcium f iuoride in acidized cores was not observed. Although some CaF* was detected, it wb.s not considered a major source of damage in cores containing moderate amounts of carbonate. Other fiuosilicates could be potentially more dangerous than CaF, in reducing permeability.

Iron sequestering agents frequently are misused and overused as acid additives. The attitude "it won't hurt and it might help" is no proper basis for choosing an iron control agent because many agents themselves can cause damage following an acid treatment. Introduction Recently there has been increased interest in using chemical additives in acid to prevent secondary precipitation of iron compounds following the acidizing precipitation of iron compounds following the acidizing treatment. Acid readily dissolves iron scale in pipe and also attacks iron-containing minerals in the formation under treatment. This dissolved iron will remain in solution in the acid until the acid is spent. As pH of the spent acid begins to rise, the iron loses its solubility and precipitates. The precipitation of ferric hydroxide or other iron-containing compounds can seriously damage the flow channels recently opened by the acid reaction in the formation. Simple calculations can be made to show that if the acid dissolved the rust in only 5,000 ft of old pipe, this would be enough to deposit more than 100 lb of damaging precipitant in the formation. While there is no question of the stoichemiometry of this calculation, it is an oversimplification of the conditions under which acid is used, and it does not account for the electrochemical behavior of the multiple valence states of iron under oxygen-free, or anaerobic conditions. Iron is a definite hazard to successful acidizing in some areas, but this does not mean sequestering agents should be routinely used unless there is positive evidence of their need. Like many chemical positive evidence of their need. Like many chemical additives for acid, iron-control agents can be misused and overused with damaging results. Some agents precipitate if the expected down hole sources of iron are not present. In some cases the iron actually keeps the sequestering agent in solution in spent acid. Thus, the effective use of iron sequesting agents depends upon the chemical conditions existing down hole during acid reaction. Since it is obviously impossible to know exactly what conditions will be encountered during an acid treatment, it is doubly important that care be used in selecting acid additives based on the best information available. In the case of iron sequestering agents there are several factors that dictate whether or not an agent should be used, and, if so, which one. Several iron-control agents are available at varying costs and each has limitations. There is no single iron-control agent available today that can economically prevent secondary iron precipitation at temperatures from 100 degrees to 250 degrees F without danger of agent precipitation if iron is not found down hole in the precipitation if iron is not found down hole in the expected quantity. This does not mean that iron sequestering agents are ineffective or not needed. It simply indicates some study should go into the decision to use an iron control agent. The thoughtless and excessive use of sequestering agents, like many other acid additives, can ruin an otherwise successful acid treatment. The Electrochemical Nature of Iron Underlying the need of an iron-sequestering agent is the chemical behavior of iron down hole when contacted with acid. JPT P. 1121

Acid corrosion-inhibitor test results are presented to demonstrate how dataon inhibitor effectiveness can be misleading and why an industry-approvedstandard method must be developed. The corrosion rate of an acid systemcan be halved simply by increasing the acid-volume/steel-area ratio. Othervariables affecting inhibitor performance are test pressure, time attemperature, chemical additives, test agitation, and type of steel. Introduction The introduction in 1932 of the arsenic acid corrosioninhibitor (ACI) primarily was responsible for thedevelopment of well acidizing. Adding a chemical inhibitorsuch as arsenic reduces the rate of acid reaction withsteel, but never completely stops the reaction undernormal treating conditions. Therefore, the type andconcentration of ACI needed to reduce the reaction rate to anacceptable level must be decided when planning an acidtreatment. The most common factors affecting ACIrequirements are bottom-hole temperature, exposure time, steel metallurgy, acid type and concentration, andsurfactant use. Acid corrosion inhibitors normally are evaluated interms of metal loss resulting from exposure to a giventype of acid at varying concentrations, temperatures, andexposure times. The most effective ACI concentrationfor a given set of conditions normally is obtained fromthis data. Testing methods thus lead to problems. Manycritical acid treatments are decided on the basis ofcomparative inhibitor performance at high temperature.In less temperature-critical situations, treatment costmay be reduced by using a cheaper ACI or alower-concentration one to give minimum desired protection.Unless test data from different sources are obtained withstandard test procedures, a true comparison of ACIperformance is impossible. performance is impossible.In spite of organized efforts, no standard test procedureexists today. Typically, the term "acceptable corrosionrate" is arbitrary and varies among companies. Also, asthe standard changes so do temperature ranges. Table 1 isan example of this variation. Table 1 indicates that ACIperformance requirements are less rigid at higher performance requirements are less rigid at higher temperatures. The question then is "Why should corrosion bemore acceptable at higher temperatures?" Actually, the entire method of comparing ACIperformance is vague and ambiguous. Data for inhibitors can be performance is vague and ambiguous. Data for inhibitors can be obtained only by designing special tests that fail tosimulate treating or down-hole conditions. Frequently, criticaldecisions are made using this data. This study points outthe effect of test conditions on inhibitor performance sothat acidizing treatment designers can understand realperformance limits on ACI systems better and can select performance limits on ACI systems better and can select the best inhibitor for existing well conditions. Some casesinvolve weighing performance claims with how the datawas obtained. The comparative effectiveness of an ACI can bejudged only in terms of laboratory simulations.Simulation quality becomes the primary factor in judging ACIperformance. Thus, we must look at test conditions that performance. Thus, we must look at test conditions that generate data affecting inhibitor choice and point out theneed for better simulation of well conditions. Also, wemust develop standards and test procedures that areuniform throughout the industry so that ACI performancedata truly is comparative. Several years ago, the API-NACE Subcommittee onCorrosion Testing began to develop a standard testmethod and equipment. The test procedure and cellspecifications are scheduled for release in 1978. JPT P. 737

Objective:The main objective of this paper is to analyse and attempt to understand the nature of rheological changes observed and the dynamics of Carbopol NF 980 hydroalcoholic gels neutralized specifically by triethanol amine (TEA), both as a function of time and alcohol type to probe time stabilities and ageing effects in such carbopol gel systems. The rheological changes and dynamics of 3 carbopol gel systems were observed; the gels included a water-based, ethanolbased, and isopropyl alcohol-based gel. It is hoped that this study shall shed light on the dynamical nature and the microstructural evolution of such networked gel systems, which were maintained under closed isothermal conditions and left completely unperturbed. The experimental results can provide the information necessary to understand and proposes plausible mechanisms guiding this dynamical behaviour in hydroalcoholic carbopol gels.Methods: A TA instrument mechanical rheometer was used to measure the viscosity and storage and loss modulus, and a pH meter was utilized to determine the changes in each sample over the period.Results: Studying the differences in the gel structures upon initial preparation illustrated that the ethanol and isopropyl alcohol (IPA) gels differed from the water-based gel in terms of viscosity, G′, and G″, with the IPA gel displaying the lowest viscosity and moduli values across all shear rates. All the three gel systems exhibited strong shear thinning characteristics and were reminiscent of yield stress type found in colloidal gels. The water-based gel compared to the hydroalcoholic gels was strongly G′ dominated, with the magnitude of the difference between G′ and G″ observed to be much higher. This reflects that initial formation of the water-based gel structure possesses a much more rigid structure with a high elastic modulus component dominating. This also suggests that the water-based gel structure displayed stronger interactions between the carbopol particles when compared to those of the hydroalcoholic gels. Over the 30-day period, it was observed that the ethanol and water-based gels did not reveal any appreciable viscosity changes, with only an approximate 12% and 7% change from day 1 to 30, respectively. It was observed that the IPA systems' viscosity drastically increased over the period, with an approximately 77% change from day 1

This paper was prepared for the 41st Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Dallas, Tex., Oct. 2–5, 1966. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Introduction A hydrofluoric-hydrochloric acid mixture containing an alcohol has proven to be highly successful in stimulating production from "problem wells" in sandstone formation. The primary advantage of this acid is the better and more rapid "clean-up" properties provided by the added alcohol. It is particularly useful in gas producing formations, particularly those with a high clay content. Many acid treatments in sandstone which would otherwise be quite successful are spoiled by a very slow spent acid clean-up. This cleanup problem is often the result of water block in the critical matrix surrounding the wellbore. The addition of alcohol to the acid can often prevent this water blocking problem and also can impart other desirable properties to the acid. Water blocking is caused by the capillary forces present in porous rock and the high mobility ratio of gas and water. Water remains around the wellbore following a stimulation or workover treatment. When the well is put back on production, the gas forces some of the water out of the rock; but after the gas breaks through, a high water saturation is left around the wellbore. This high water saturation reduces the effective permeability of the sand to gas. As the water or spent acid is produced, the gas production rate may increase, but many hours or days will be required to establish optimum production following treatment. Some wells require as much as 3 months to a year to regain the initial gas production rate following liquid injection into the formation. The severity of water blocking increases in low permeability formations where the capillary forces are high or in gas producing formations where the reservoir pressure is low. Liquid saturation hurts the effective permeability of gas even more in formations with large variations in porosity and permeability. An extreme example of this is shown in Figure 1 from a study by Corey and Rathjens. In this case, tight sections are in series with very permeable sections. Here the gas permeability is low even at low average liquid saturations. This behavior may also result from aggregates of migrated clay particles contained in the pores of the rock. These types of reservoir rock can result from the geological conditions of sedimentation which are discussed below.