In this paper, an integrated analysis and design method is presented to understand and quantify the effect of particle jamming near the entrance of perforation/wormhole tunnel. An advanced wellbore-scale three dimensional numerical studies with a coupled computational fluid dynamics (CFD) and discrete element model (DEM) were performed to simulate different mechanisms involved in particulate diversion. The results of wellbore-scale simulation were translated into an engineering particulate diversion model, based on the proven diversion mechanisms from laboratory and simulation. The model is incorporated into an integrated carbonate acidizing simulator. Generally particulate diversion is not used in carbonate acidizing because of the formation of the wormholes and potential difficulty in removing particles from the induced wormholes or perforation tunnel. The new degradable particulate system addresses the issue and presents an efficient approach to divert acid in carbonate stimulation. Detailed physics based simulation demonstrate that the induced wormholes or perforation would plug thru two distinct mechanisms: (1) temporarily seal the entrance of small scale wormholes or perforation with a combination of small and large particles, and/or (2) large particles bridge along tapered path of wormhole/perforation and forms a temporary filter cake on the mouth of opening. Either of these diversion mechanisms will decrease the injectivity locally and promote fluid diversion from inside of well into other normally under-stimulated locations. The integrated simulator is used to optimize acid stimulation of a vertical wellbore and explain the impact of operational parameters and subsurface conditions on the stimulation efficiency. The model results showed that most optimized bullheaded treatment can be significantly improved by utilizing the particulate diversion system. It is shown that that the developed skin from jammed particulate provided considerable diversion. The results also demonstrated the relation between treatment pressure, the quality of diversion, and subsurface conditions (e.g. permeability, porosity, reservoir pressure and temperature).

Abstract The Niagaran formation in the Michigan basin is comprised of Silurian Pinnacle reefs. It is a heterogeneous carbonate formation with the majority being dolomite. There are two Niagaran plays in Michigan, the Northern Play and the Southern Play. Past stimulation treatments on the Niagaran have consisted of mainly hydrochloric acid at concentrations of 15–28%. Most treatments were kept to matrix conditions due to water zones in close proximity. These treatments usually yield marginal results due to the acid being spent mostly near well bore. Gelled, crosslinked or emulsified acid are good solutions for this problem but can also leave some damage behind. Acid gelled with surfactants can yield similar results and be easier to clean up. This paper will provide some background on the Niagaran formation and historical treatments. The paper will explain the chemistry behind viscoelastic surfactant-based acid systems and will provide detailed descriptions of the benefits of these types of systems. Production data from a well treated with both conventional acid and a viscoelastic acid system will be discussed. The paper will then conclude with a few words on the economics behind viscoelastic systems. Introduction Oil producing formations like the Michigan Basin's Niagaran Reef are getting more attention now than in the recent past. This attention is fueled by the recent down turn in gas pricing along with the fact that oil prices appear to be making an earlier comeback. When dealing with oil formations that produce less than spectacular amounts of oil per day, it is important to perform effective stimulation jobs that don't damage the formation. Acidizing carbonate formations such as the Niagaran is an easy and usually inexpensive solution to stimulation. Finding the optimum acid blend for the formation, however, can sometimes be challenging. Regular hydrochloric acid mixed at concentrations of 15–28% works well in the Niagaran but may dissolve more near-wellbore formation rock and not reach out into the reservoir as desired. As a result, gelled, crosslinked or emulsified acids systems have demonstrated successes. One of the main benefits of using gelled, crosslinked or emulsified acid systems is that by encapsulating the acid, the contact time between the acid and formation rock can be delayed. This allows more time for the acid to reach out into the reservoir before spending itself by dissolving formation rock. The same effect could be accomplished with a weaker acid system, but by using an encapsulated acid system, strength isn't sacrificed. The only drawback to using encapsulated systems is breaking them. This is not an exact science. If they are not properly broken, they can leave damaging gels or emulsions, plugging off pore spaces and restricting formation fluid from flowing to the well bore. One solution to this problem is gelling systems with surfactants. A viscoelastic surfactant-based gelling system can achieve the same results as an encapsulated system but with better control over the break. Viscoelastic surfactant-based systems use large loadings of surfactants to create a polymer-style gel. The benefit of this gel over normal polymer gels is that it is sensitive to pH and hydrocarbon. This means that in an acid system, as the pH changes, so do the gel characteristics. By the time the acid system has reached a neutral pH, the gel will have broken back to a liquid form. If for some reason some gel remains, the system's hydrocarbon sensitivity means it will break when it comes in contact with formation fluids.

Abstract Emulsified acid (30 vol% diesel and 70 vol% HCl acid) has been used in both matrix and acid fracturing treatments. Injection the acid in this form has several advantages including: retard the reaction of the acid with rock, reduce corrosion to well tubulars and minimize acid additives. However, using this acid to treat wells with asphaltene deposition will require removing asphaltene first using a suitable aromatic-based solvent, and then using a matrix acid treatment. This additional step will increase the cost and time needed to execute acid treatments. To remove asphaltene deposition and enhance well productivity, hydrochloric acid was emulsified in xylene. Xylene was the external phase, and was used to dissolve asphaltenes. Then the acid, present as the dispersed phase dissolved the carbonate rock, thus enhancing well productivity. Extensive lab work was performed to ensure the stability of acid-in-xylene emulsion and measure its apparent viscosity. Acid concentration was 15 wt% HCl, the acid volume fraction was 0.7 and the balance was xylene. All tests were conducted at room temperature and 160oF. The stability and apparent viscosity of emulsified acids were found to be a function of the type of hydrocarbon phase used to prepare emulsified acid. Emulsified acids prepared with xylene had a lower apparent viscosity and were stable for relatively shorter period of times. A matrix acid treatment was that based on xylene emulsified acid was applied in four wells without encountering operational problems. Unlike previous matrix acid treatments using regular acid, the four wells responded to the new treatment, without increasing water-cut, except in one well which was wet before the treatment. Introduction Diesel is commonly used to prepare emulsified acids. It acts as a diffusion barrier between the acid and the rock (Crowe and Miller, 1974; Bergstrom and Miller, 1975, Hoefner and Fogler, 1985; Daccord et al., 1987; Peters and Saxon, 1989). Thus, the reaction rate of the acid with carbonate rocks becomes slower. This gives the acid the ability to penetrate deeper into the formation by creating wormholes (i.e., channels with high permeability), which enhance well performance (Williams and Nierode, 1972; Guidry et al., 1989; Navarrete et al. 1998a,b) Acid-in-diesel emulsion has several advantages besides its slow reaction rate with the rock. It has a relatively high viscosity, which results in a better sweep efficiency that will improve acid distribution in heterogeneous reservoirs (Buijse and van Domelen, 1998). The live acid does not come in contact with well tubulars. Therefore, there is minimum corrosion to well tubulars. As a result, the concentration of iron in the live acid reaching the formation will be low, which will reduce the amount of iron control agents (Al-Anazi et al., 1998). Several studies (de Rozieres et al., 1994; Conway et al., 1999; Kasza et al., 2006; Al-Mutairi et al., 2008a) examined the reaction of emulsified acid with carbonate rocks. The rotating disk apparatus was extensively used and the results of these studies indicated that the reaction of emulsified acid with carbonate rocks is slower than that of regular acids. Al-Mutairi et al. (2008a) indicated that the size of the acid droplets affected the reaction rate. And this should be considered as an important parameter in designing acid treatments. In a second study, Al-Mutairi et al. (2008b) examined the impact of the droplet size on the rheological properties of acid-in-diesel emulsions. Propagation of emulsified acids in carbonate cores was examined by several research groups (Bazin and Abdulahad, 1999; Lynn and Nasr-El-Din, 2001; and Siddiqui et al., 2006). These studies indicated that the acid propagated through the core plugs in almost straight lines. The acid enhanced core permeability by a factor that depended on the acid injection rate.

Abstract The demand for hydrocarbon production increases each year as world population continues to grow and more energy is consumed. This increasing demand has caused the oil and gas industry not only to develop new technology but also to develop reservoirs that were previously overlooked. These marginal reservoirs were deemed uneconomic, primarily because they typically existed on the outer fringes of known reservoirs or the potential productive formations were subject to excessive water production. Many of these previously-overlooked reservoirs need to be hydraulically stimulated to make them economic. When using fracture stimulation to complete a wellbore in marginal reservoirs, it is not uncommon to produce excessive amounts of water. This excessive water production can come from the producing formation, water-wet formations which bound the producing interval, or lack of sufficient barriers between the productive zone and nearby water-bearing zones. Because wells drilled in these marginal reservoirs are economically borderline, any additional water production resulting from the completion of these wells jeopardizes the already questionable economics. Consequently, the operators run a much higher economic risk when completing wells in these marginal reservoirs. This paper describes a case history using a relative permeability modifier (RPM) incorporated into a hydraulic fracture stimulation treatment to reduce excessive water production. By implementing this process, it gives the operator an additional tool to increase the chances of producing formations containing hydrocarbons which had been previously overlooked. Therefore, this process can help reduce the higher economic risk of completing marginal reservoirs. Incorporating this technique into a fracture stimulation treatment resulted in the best producing well in the study area. Introduction With the world's demand for additional hydrocarbon production increasing every year, more marginal reservoirs are being explored. These reservoirs were overlooked in the past because of their potential for excessive water production after hydraulic stimulation treatments. Since the beginning of the modern oil and gas industry, water production has been a problem that has plagued operators. It can cost as much, if not more, to produce a barrel of water as it does to produce additional hydrocarbons. Water production can also lead to additional costly problems such as scale, corrosions, production fines, etc. (Dalrymple et al. 1998). Water production, regardless of the reason, can hinder and in some cases result in complete loss of hydrocarbon production. If no action is taken once the water production occurs, the problem typically worsens before it becomes better. The industry has dealt with this by separating the produced water from the hydrocarbons, then disposing of it. There are more regulations each year regarding the handling and disposing of produced water, which continually increases the cost of handling this water. Another method used within the industry is squeezing portions of the wellbore with a plugging agent, usually cement, to reduce or stop water production. Care must be taken when using a plugging agent to reduce water production because if the product is not placed in the proper area of the reservoir, it can shut off hydrocarbon production and water production. Also, depending on the product used, depth penetration can be limited to near-wellbore, which sometimes results in a temporary fix. Anything that can reduce or stop water production benefits the operator and the industry. This paper will describe a process used on hydraulic stimulation treatments of wells that helps reduce the risk of producing excessive water. This process uses a RPM as a spacer introduced at the beginning of a hydraulic stimulation treatment that helps minimize the risk of producing excessive water.

Arthur Steven Metcalf, SPE, BJ Services Company, U.S.A. Abstract Acid stimulation using coiled tubing conveyance is becoming commonplace; however, protection of these coils from acid corrosion is challenging. Add to this the requirement for usage of materials less damaging to the environment, and the task approaches the impossible at high temperatures >250) and high acid strengths >20). The common requirement of corrosion weight loss for jointed tubulars (N-80, J-55, L-80, CR-13, etc.) is <0.05 pounds per square foot and <0.02 to <0.03 for coiled tubing. Increasing acid strength and/or temperature causes an increase in the corrosion inhibitor package cost by nearly 400% as the conveyance tubular changes from N-8O to coiled tubing. Included in this paper is a comparison of corrosion data generated for hydrochloric acid systems from 20 to 28% on coiled tubing, N-80 and CR-13. The inhibitor evaluated is a blend of select solvents, activated ketone, a small quantity of acetylenics, surfactant and an amine. This material is given a Group "C" designation under the Revised Offshore Chemical Notification Scheme. A summary of the information used to define this inhibitor's Group "C" designation is presented. P. 357

Abstract Acidizing has typically been one of the most popular techniques used for the removal of damage in gas storage wells. Acidizing is often useful for carbonates, but surveys have indicated that as many as 30% of the sandstone wells were adversely affected by the use of acids. This paper will discuss various conditions that should be evaluated when considering the use of acids for remediation or stimulation in gas storage wells. These conditions include mineralogy, completion type, and operational considerations such as the well's capacity to return fluids to the surface, types of acids and their associated chemistry, and reservoir characteristics. This paper will also evaluate the use of acids with respect to the most frequently observed types of damage mechanisms. These mechanisms were recently determined in a Gas Research Institute damage-mechanism study involving 32 wells and 12 gas storage reservoirs. Evidence of at least two wells that have been adversely affected by acid will be discussed, and general guidelines for the use and types of acids and appropriate placement techniques will be given. Introduction In 1993, a GRI-funded project reported on the deliverability enhancement technology currently being used by the gas storage industry. Part of this review indicated that most gas storage operators experience an average deliverability loss of approximately 5% over 1 year in the more than 400 U.S. storage reservoirs representing approximately 15,000 individual wells. The study also estimates that tens of millions of dollars are spent each year to recover or replace deliverability and to maintain the current rate of deliverability. The most widely used deliverability enhancement techniques are washing, acidizing, reperforation, and infill drilling. More than 100 acidizing treatments in all types of reservoirs were evaluated in this survey. Acidizing was performed 50% more frequently on carbonates than on sandstones, and all results were reported as good to excellent. Of the 63 sandstone treatment responses evaluated, only 15% had excellent results, and 20 to 30% had poor results. Deliverability enhancement costs for acidizing are estimated at 4 to 20 million dollars. The conclusions drawn from this data are that acidizing a carbonate is more effective than acidizing a sandstone, and that a lack of knowledge about acidizing sandstones contributes to the lower success rate in these formations. Considerations for Acidizing Gas Storage Formations Damage Mechanisms. The first consideration before applying any type of deliverability enhancement technique should be the type of damage that is to be removed. A clear understanding of the damage mechanism is needed before a proper remedial/enhancement technique can be applied. Without this understanding, ineffective and/or inappropriate methods may be chosen, and remedial dollars may be wasted. A second GRI-funded research initiative was undertaken to provide a fundamental understanding of the formation damage mechanisms responsible for deliverability loss and their cause-effect relationships to deliverability loss in a broad spectrum of gas storage reservoirs. For this study, researchers used well testing, downhole samples taken with bailers, rotary sidewall coring, and downhole video as their primary investigative tools, and identified the following eight major damage mechanisms as potential problems in gas storage reservoirs: – bacteria – inorganic precipitates such as salts, carbonates, sulfides, etc. – hydrocarbons, organic residues, and production chemicals - particulate plugging – completion/stimulation fluid effects P. 113^

Abstract A simple and practical process has been developed to heat hydrochloric acid to improve its performance as an oil well stimulating agent. Heated acid is used in cold formations, such as cold dolomites, to increase the rate at which the formation is dissolved, thus improving flow capacities. The new technique heats the acid by causing an exothermic chemical reaction that uses a portion of the HCl as one of the reactants. Heated acid reacts at a faster rate and aids in removal of acid-retarding materials such as oil, asphaltene and paraffins from the formation to give a better acid-to-formation contact. Some other benefits of heating acid are: Helps prevent precipitation of organic materials from oils that have been cooled by acids. Limits the amount of tubing contraction due to temperature change. Problems presented by the slow reaction time Problems presented by the slow reaction time HCl in cold formations and the special problems of conducting winter time acid treatments are largely solved by heating HCl up to bottom hole temperature or more prior to pumping. This paper presents laboratory and field results to illustrate the effectiveness of the heated acid method of stimulation and compares the various methods of bringing the acid to its ideal temperature. Introduction Stimulation of formations with cold treating fluids causes a variety of problems to the oil industry. 1. Cold treating fluids are not reactive enough, especially when the formations are themselves cool. 2. Tubular goods will contract excessively when the formation is hot and the treating fluid is cool. Contraction can cause strain on the tubular goods and unseating of packers. Historically, in acidizing emphasis has been on the use of retarded acids or retarded systems that place live acid deeper into the formation; place live acid deeper into the formation; however, studies have shown that in many ways accelerated acid systems are necessary because of cold formations or short acid pumping times. Although surfactants can aid to some degree, the most practical means to accelerate the acid reaction has practical means to accelerate the acid reaction has been found to be heating the acid. Hot oilers and steam have been used to heat acid, but their application with many acid systems was limited or they were impractical for the type of treatment to be run. A system to chemically heat acid has been developed and tested in the laboratory and field, showing excellent results. METHODS OF HEATING ACID Chemically Heated Acid Heating acid by chemical means can be accomplished by either batch or continuous methods. The batch heating process consists of flowing ammonia into the container below the surface of the acid by means of a perforated lance. Ammonia is added until the desired temperature or acid concentration is reached. Figure 1 shows the heat derived from three different acid solutions. Large volumes of acid can also be heated simply by the continuous method. Ammonia is metered into the acid while the acid is being pumped into the well. Heat is developed rapidly and there is little heat loss on the surface since there is no exposure or delay. Heat used to warm acid is derived from (1) the equation of ammonia and (2) neutralization of the aquated ammonia by hydrochloric acid to make ammonium chloride. Table 1 lists some other compounds capable of heating acid. Hot Oilers Generally, acid is not run through hot oiler systems because of a potential for corrosion. p. 159

Members SPE-AIME Abstract The Appalachian Basin presents one of the most challenging production and stimulation problems because of the iron content of its hydrocarbon producing formations. A variety of iron compounds in the producing formations present problems that have to be considered to effectively stimulate these formations. These iron compounds present three major problems: Relatively insoluble iron compounds that may be released by acidizing fluids and have a plugging effect when they migrate; Acid soluble iron compounds that may reprecipitate when the acid spends; and Aerated fracturing fluids being incompatible with formation waters that contain ferrous iron. A research program was initiated in the later part of 1980 to determine methods of more effectively controlling the iron problems in the Appalachian Basin. Results of this study provide data for comparing the effectiveness of various iron control systems that are used in acid stimulation or breakdown techniques that minimize the release of acid insoluble solids and stabilizes them to decrease the detrimental effect caused by fines migration. Also developed in this study was an iron control system that helps the compatibility of the treating fluid with ferrous iron in the formation water. Flow test data and field results indicate the effectiveness of these iron control systems and treating techniques. Introduction Production and stimulation problems have been encountered in the Appalachian Basin because of the iron content of some of the hydrocarbon producing formations Iron control studies previously have dealt primarily with iron control in acidizing operations. Acid primarily with iron control in acidizing operations. Acid solutions progressively dissolve iron and iron compounds as they are mixed in the acid tanks, pumped through tubular goods, and into the formation. If the acid does not contain an effective iron control system, the dissolved ferric (Fe) iron will start to precipitate when the acid spends to a pH of 2.5 and will precipitate when the acid spends to a pH of 2.5 and will approach complete precipitation when the pH increases to 3.5. Iron compounds such as magnetite and hematite are slowly soluble in acid, while pyrite is relatively insoluble in acid. The acid may spend on rapidly soluble material in the formation and release the relatively insoluble or slowly soluble compounds. The released solids may migrate, bridge flow channels, create cleanup problems, decrease production, and increase the rate of production decline after stimulation. Fracturing fluids, other than the breakdown acid, are usually non-acidic or weakly acidic solutions that dissolve very little iron (less than 5 mpl). Iron had not been recognized as an important factor in fracturing treatment design prior to about 1977. Ferrous (Fe ++) iron in a formation water will remain in solution at the pH of the natural formation environment. However, an aerated treating fluid may mix with the formation water and oxidize the ferrous iron to ferric iron. Ferric iron will then precipitate at the pH of the natural environment. This precipitate at the pH of the natural environment. This precipitate is considered detrimental to the stimulation precipitate is considered detrimental to the stimulation operation. Ammonium citrate has been used as a iron control agent in fracturing fluids. Ammonium citrate chelates iron and was effective to some extent. However, like other metal chelating agents [citric acid, ethylene-diamine tetracetic acid (EDTA), nitrilotriacetic acid (NTA) and modifications thereof], it is incompatible with most of the metallic crosslinking systems that are used to form cross-linked gels. Cross-linked gels are popular because of their proppant carrying ability. A research project was initiated to obtain an improved iron control system for fracturing fluids and to develop treating techniques that would improve production stimulation and production decline. production stimulation and production decline. P. 203

Introduction Asphaltene precipitation is currently undergoing a major observation by the petroleum industry due to the problem it can create, such as the reduction of fluid flow passages. In particular, this could include the reduction of formation permeability. This experimental study encompasses the role the acid, and the chemicals often added during formation stimulation could have in precipitating asphaltenes from some crude oils. That is, sometimes unstable colloidal materials in asphaltic base crudes coagulate when subjected to acid stimulation and form deposits on the wellbore and on the formation faces. These deposits have been found to consist of paraffins, resins, maltenes, and asphaltenes. The paraffins, resins, maltenes, and asphaltenes. The asphaltenes that precipitate out are not single molecules, but clusters of molecules often coated with paraffin and resin molecules strongly bonded to the exterior of the clusters. To investigate sufficiently the role played by acid-additive mixtures on asphaltene precipitation in open systems and in porous media, a study was first made to determine the total amount of asphaltene precipitation as a function of solvent concentration precipitation as a function of solvent concentration using asphaltic base crudes. Further studies were made to determine the amount of asphaltene precipitation of the same crudes, using acid-additive mixtures precipitation of the same crudes, using acid-additive mixtures commonly used in acid-stimulation treatments. Additional investigation was completed to attempt determination of the extent of plugging due to asphaltene precipitation during the acidizing of a linear model using consolidated Berea sandstone cores. CRUDES USED FOR STUDY The crudes used for this study were the Lloydminster crude from Alberta, Canada, and the Lake Maracaibo and Mouchal crudes from Venezuela. The Lloydminster was used to check the effects of all the available acid-additive mixtures and to observe the possible effects of asphaltene precipitation on flow possible effects of asphaltene precipitation on flow in a porous media; whereas the Lake Maracaibo and the Morichal crudes were used for a complete solvent study and also checked with the acid-additive mixtures that precipitated significant amounts of asphaltenes. APPARATUS AND EXPERIMENTAL PROCEDURE The separation of the asphaltenes from the crudes was completed by the following equipment: a Ruska Mercury Displacement Pump, a Millipore Filter, and a high-pressure sample reservoir, according to Fig. 1. The procedure for separating the asphaltenes is begun by first weighing out samples of the test crude into preweighed sample bottles. Next, determine the amount of solvent to be mixed volumetrically with the crudes in 20, 40, 60, and 80% solvent-to-crude concentrations. Add the desired amount of solvent to the appropriate crude sample and mix thoroughly. In this study, Talboys Instrument Corp. magnetic, variable-speed mixer was utilized at 15 minutes per sample. The actual separation of the asphaltenes from a crude sample was achieved by emptying the contents of one sample bottle into the stainless-steel reservoir. Any crude remaining in the sample bottle should be washed with 5 ml of naphtha and emptied into the reservoir. A Millipore Filter containing a 5-micro p filter paper was attached to the outlet end of the p filter paper was attached to the outlet end of the reservoir and the sample bottle positioned to collect the filtered crude. The Ruska Mercury Pump now is used to displace the crude out of the sample reservoir and through the Millipore Filter, there all particles 5-micro p and larger were collected on the filter paper. The 5-micro 4 filter paper is removed now and paper. The 5-micro 4 filter paper is removed now and replaced with a 1-mu filter paper. The crude sample then is re-emptied into the reservoir and the same procedure repeated with a 1-micro 4 filter paper. procedure repeated with a 1-micro 4 filter paper. FRACTIONAL DISTILLATION OF THE ASPHALTIC MIXTURES In order to isolate the asphaltenes, the following apparatus was implemented: 250-ml flasks, a distillation chamber, and a sample chamber, according to Fig. 2.