It has been a practice to use seawater for preparing acid in offshore operations where fresh water is relatively expensive or logistically impossible to use. However, hydrochloric acid will release calcium ion into solution, which will combine with sulfate ion in seawater (greater than 3000 ppm) and calcium sulfate will precipitate once it exceeds its critical scaling tendency. A few studies have provided evidence for this problem and how to address this problem has not been fully examined. Core flood tests were conducted using Austin Chalks cores (1.5 in. x 6 in. and 1.5 in. x 20 in.) with permeability 5 md to investigate the effectiveness of scale inhibitor. A synthetic seawater was prepared according to the composition of seawater in the Arabian Gulf. Calcium, sulfate ions, and scale inhibitor concentrations were analyzed in the core effluent samples. Solids collected in the core effluent samples were analyzed using X-ray photoelectron spectroscopy (XPS) technique and thermodynamic calculation using OLI Analyzer software were conducted to identify the critical scaling tendency of calcium sulfate at different temperatures. Results showed that calcium sulfate precipitation occurred when seawater was used in any stage during matrix acidizing including preflush, post-flush, or in the main stage. Injection rate was the most important parameter that affected calcium sulfate precipitation; permeability reduction was significant at low flow rates, while at high rates wormhole breakthrough reduced the severity of the problem. More CaSO4 precipitated at high temperatures, accounting for more significant permeability reduction in the cores. The values of critical scaling tendency at various temperatures calculated by OLI ScaleChem 4.0.3 were believed to be 2.1, 2.0, and 1.2 respectively. A scale inhibitor (a sulfonated terpolymer) was found to be compatible with hydrochloric acid systems and can tolerate high concentration of calcium (30,000 mg/l). Analysis of core effluent indicated that the new treatment successfully eliminated calcium sulfate scale deposition. The concentration of scale inhibitor ranged from 20 to 250 ppm, depending on the scaling tendencies of calcium sulfate. This work confirms the damaging effect of preparing hydrochloric acid solutions using seawater on the permeability of carbonate cores. Therefore, it is recommended to use fresh water instead of seawater to prepare HCl acids whenever possible. If fresh water is not available, then a proper scale inhibitor should be added to the acids to avoid calcium sulfate precipitation.

Sandstone acidizing has been carried out with mud acid which combines hydrochloric acid and hydrofluoric acid at various ratios. The application of mud acid in sandstone formations has presented quite a large number of difficulties like corrosion, precipitation of reaction products, matrix deconsolidation, decomposition of clays by HCl, and fast spending of the acids. There has been a recent trend to use chelating agents for stimulation in place of mud acid which are used in oil industry widely for iron control operations. In this study, two chelates, L-glutamic-N, N-diacetic acid (GLDA) and hydroxyethylethylene-diaminetriacetic acid (HEDTA) have been studied as an alternative to mud acid for acidizing. In order to analyze their performance in the application of acidizing, coreflood tests were performed on Berea and Bandera sandstone cores. Another disadvantage of mud acid has been the fast spending at clay mineral surfaces leading to depletion of acid strength, migration of fines, and formation of colloidal silica gel residue. Hence, compatibility of chelates with clay minerals was investigated through the static solubility tests. GLDA and HEDTA were analyzed for their permeability enhancement properties in Berea and Bandera cores. In the coreflood experiments conducted, it was found out that chelating agents can successfully stimulate sandstone formations. The final permeability of the Berea and Bandera cores were enhanced significantly. GLDA performed better than HEDTA in all applications. The substitution of seawater in place of deionized water for mixing purposes also led to an increased conductivity of the core implying GLDA is compatible with seawater. In the static solubility tests, chelates were mixed with HF acid at various concentrations. GLDA fluids kept more amounts of minerals in the solution when compared with HEDTA fluids. Sodium-based chelates when mixed with HF acid showed inhibited performance due to the formation of sodium fluorosilicates precipitates which are insoluble damage creating compounds. The application of ammonium-based chelate with HF acid was able to bring a large amount of aluminosilciates into the solution. The study recommends the use of ammonium-based GLDA in acidizing operations involving HF acid and sodium-based GLDA in the absence of the acid.

Sandstone acidizing is a complex operation because the acidizing fluid reacts with a variety of minerals present in the formation that results in a wide range of reaction products. The hydrofluoric acid (HF) reaction rate differs widely from mineral to mineral because of the variation in the reaction rate and the area of contact with the injected fluid. The series of reactions occurring in sandstone makes it all the more difficult to find the exact individual reaction rate constants. An improved model that provides better estimates of the outcome of a sandstone acidizing treatment is developed following a review of previous sandstone acidizing models. The model follows the lumped mineral methodology and is based mainly on the kinetic approach. The use of accurate reaction-rate laws allows the model to effectively predict the consumption of acidizing fluid during the stimulation treatment. The consideration of a proper equation for the silica gel filming factor accounts for the fact that some clay becomes inaccessible to the acid when silica gel precipitates on their surface. The proposed model is shown here to be valid in extrapolating laboratory coreflood data and predicting the effluent acid concentration at various flow rates. The damage during sandstone acidizing can be minimized when stimulation treatments are designed according to the percentage of carbonate in the formation, type and amount of clay in the formation and the reservoir bottomhole temperature. Most of the available software for design and evaluation of acidizing treatments do not consider the temperature and mineralogy effects extensively. We studied one such software and developed recommendations to improve the design and evaluation of sandstone acidizing treatments by taking into account the multifaceted effects of temperature and mineralogy in increasingly deep and hot sandstone environments. These recommendations will be of great use in the times to come as most of the wells will have to be drilled at greater depths in search for new reserves.

Surfactant flooding in carbonate matrix acidizing treatment has been widely used for changing the wettability of the rock and to achieve low IFT values. Optimizing the type of surfactant and concentration for the specific oil field is very important in order to avoid formation damage and to reduce the treatment cost. We built an experimental procedure for screening the right surfactant to alter the wettability and aid in acidizing of Pekisko formation, Canada, which is strongly oil-wet and has high viscosity oil. Five surfactants were tested out of which three are cationic, one amphoteric and the other one was a fluoro-surfactant. Measurements were made of interfacial tension with different surfactant types/concentrations in brine with the oil and xylene, critical micelle concentration of each surfactant, solubility characteristics of the surfactants, compatibility of the chemical additives, wettability of the core after treating with surfactants, and core flooding in the laboratory to simulate matrix acidizing. From the results obtained we noted that the fluoro-surfactant can cause formation damage due to precipitation in the brine. So the compatibility of every chemical additive should be tested first. The use of xylene as a pre-flush solution lowered the CMC and hence reduced the cost of the surfactant treatment. Aromox, an amine based surfactant was best suited for matrix acidizing treatment of the Pekisko formation.

In this study, the optimum conditions for wormhole propagation in horizontal well carbonate acidizing was investigated numerically using a horizontal well acidizing simulator. The factors that affect the optimum conditions are rock mineralogy, acid concentration, temperature and acid flux in the formation. The work concentrated on the investigation of the acid flux. Analytical equations for injection rate schedule for different wormhole models. In carbonate acidizing, the existence of the optimum injection rate for wormhole propagation has been confirmed by many researchers for highly reactive acid/rock systems in linear core-flood experiments. There is, however, no reliable technique to translate the laboratory results to the field applications. It has also been observed that for radial flow regime in field acidizing treatments, there is no single value of acid injection rate for the optimum wormhole propagation. In addition, the optimum conditions are more difficult to achieve in matrix acidizing long horizontal wells. Therefore, the most efficient acid stimulation is only achieved with continuously increasing acid injection rates to always maintain the wormhole generation at the tip of the wormhole at its optimum conditions. Examples of acid treatments with the increasing rate schedules were compared to those of the single optimum injection rate and the maximum allowable rate. The comparison study showed that the increasing rate treatments had the longest wormhole penetration and, therefore, the least negative skin factor for the same amount of acid injected into the formations. A parametric study was conducted for the parameters that have the most significant effects on the wormhole propagation conditions such as injected acid volume, horizontal well length, acid concentration, and reservoir heterogeneity. The results showed that the optimum injection rate per unit length increases with increasing injected acid volume. And it was constant for scenarios with different lateral lengths for a given system of rock/ acid and injected volume. The study also indicated that for higher acid concentration the optimum injection rate was lower. It does exist for heterogeneous permeability formations. Field treatment data for horizontal wells in Middle East carbonate reservoirs were also analyzed for the validation of the numerical acidizing simulator.

Mud acid, which is composed of HCl and HF, is commonly used to remove the formation damage in sandstone reservoirs. However, many problems are associated with HCl, especially at high temperatures. Formic-HF acids have served as an alternative of mud acid for a long period. Several factors may influence the outcome of an acidizing job in sandstone formations. In this research, effects of mineralogy, temperature, and HF concentration were studied. Various clay minerals (kaolinite, chlorite, and illite) were examined to react with formic-HF acid mixtures which contain different concentrations of HF. Coreflood experiments on sandstone cores featured by different mineralogy with dimensions of 1.5 in. x 6 in. were also conducted at a flow rate of 5 cm^3/min. Formic or acetic acids were used in preflush stage to remove the carbonates. A series of formic-HF acid mixtures with different ratios and concentrations were tested, and temperature varied from 77 to 350 degrees F. Inductively coupled plasma (ICP), scanning electron microscopy (SEM) and 19F nuclear magnetic resonance (19F NMR) were employed to follow the reaction kinetics and products. Besides, acetic-HF acid system, which is another important alternative of mud acid, was also investigated to compare with formic-HF acids. The species and amounts of reaction products of different clay minerals in organic-HF acids depend on mineral type, acid composition and ratio, and this is further confirmed by coreflood experiments, in which sandstone cores with different mineral compositions give quite different responses to the same acid mixture. As preflush, formic acid becomes more effective in removing carbonate minerals in sandstone cores at higher temperatures. In main flush stage, more concentrated HF can react with more clay minerals, but can also cause higher risk of CaF2 precipitate. Both formic-HF and acetic-HF acids are much milder than mud acid. When reacting with clay minerals, there is no big difference in the behaviors of 13 wt% acetic-HF acids and 9 wt% formic-HF acids, as long as the HF concentrations are the same.

Carbonate reservoirs are heterogeneous; therefore, proper acid placement/diversion is required to make matrix acid treatments effective. Viscoelastic surfactants (VES) are used as diverting agents in carbonate matrix acidizing. However, these surfactants can adversely affect wettability around the wellbore area. Lab and field studies show that significant amounts of VES are retained in the reservoir, even after an EGMBE postflush. Optimizing acid treatments requires a study of the effect of VES on wettability. In a previous study using contact angle experiments, it was reported that spent acid solutions with VES only, and with VES and EGMBE are water-wetting. In this thesis, we studied the effect of two amphoteric amine-oxide VES', designated as "A" and "B" on the wettability of Austin cream chalk using contact angle experiments. We extended the previous study by using outcrop rocks prepared to simulate reservoir conditions, by demonstrating that VES adsorbs on the rock using two-phase titration experiments, by studying the effect of temperature on wettability and adsorption, and by developing a detailed procedure for contact angle experiments. We found that for initially oil-wet rocks, simulated acid treatments with VES "A" and "B" diversion stages and an EGMBE preflush and postflush made rocks water-wet at 25, 80, and 110 degrees C. Simulated acid treatments with a VES "A" diversion stage only made rocks water-wet at 25 degrees C. Our results suggest that both VES formulations cause a favorable wettability change for producing oil. The two-phase titration experiments show that both VES "A" and "B" adsorb on the rock surface. From our literature review, many surfactant wettability studies use contact angle measurements that represent advancing contact angles. However, wettability during stimulation is represented by receding contact angles. Results of static receding contact angles may be misinterpreted if low oil-acid IFT's cause oil droplets to spread. Spreading could be a reflection of the effect of the surfactants on the fluid-fluid interface rather than the rock-fluid interface. The new procedure shows the effect of VES and EGMBE on the rock-fluid interface only, and so represents the actual wettability.

Emulsified acids have been extensively used in the oil industry since 1933. Most of the available research and publications discussed mainly the application of emulsified acid in the field. A fair number of the published work also discussed in depth some of the emulsified acid properties such viscosity, stability and reactivity. However, all of the available research discussed the emulsified acid without sufficient details of its preparation. Beside their chemical composition, the ways emulsified acids are prepared cause significant differences in their physical properties. The characterization of emulsified acid by its droplet size and size distribution complements its chemical composition and gives the emulsified acid a unique description and thus reproducible properties. No previous study considered the impact of the droplet size on the characteristics and properties of emulsified acid. Therefore, the main objective of this research is to study the effects of the droplet size on various properties of emulsified acid such as viscosity, stability and reactivity. Results showed that the droplet size and size distribution have a strong effect on the stability, viscosity and diffusion rate of the emulsified acid. The results of this work are important because knowledge of the effect of the droplet size on major design parameters will guide the way emulsified acid is prepared and applied in the field.

Iron control during acidizing plays a key role in the success of matrix treatment. Ferric ion precipitates in the formation once the acid is spent and the pH exceeds 1-2. Precipitation of iron (III) within the formation can cause formation damage. Chelating agents such as EDTA and NTA are usually added to acids to minimize iron precipitation. Drawbacks of these chelating agents include limited solubility in strong acids and poor environmental profile. Hydroxy EDTA was introduced because of its higher solubility in 15 wt% HCl. However, its solubility in 28 wt% HCl is low and it is not readily biodegradable. In this study we studied the formation damage caused by iron precipitation in acidizing operations and tested the chelate L-glutamic acid, N,N-diacetic acid (GLDA). This chelant is soluble in higher concentrations of HCl. It is readily biodegradable, and is an effective iron control agent. A study was conducted to study the concentration of iron at different pHs ranging from 1-4 without the presence of any chelating agent at room temperature. A similar study was conducted in the presence of a chelating agent. To simulate field conditions, coreflood tests were conducted on Indiana Limestone, Austin Chalk and Pink Desert. Tests were conducted with and without the chelant. Samples of core effluent were collected and iron and calcium concentrations were measured using atomic absorption spectroscopy (AA). The cores were scanned using X-ray before and after acid injection. Results indicated that precipitation of iron can cause serious reduction in core permeability. The chelate was found to be very effective in chelating iron upto 300 degrees F. No permeability reduction was noted when GLDA was added to the acid. Material balance calculations show that significant amount of the iron that was added to the injected acid was produced when GLDA was used. This chelant is effective, environmentally friendly and can used up to 300 degrees F.

Viscoelastic surfactant have found numerous application in the oil fields as fracturing and matrix acidizing fluid additives in the recent years. They have the ability to form long worm-like micelles with the increase in pH and calcium concentration, which results in increasing the viscosity and elasticity of partially spent acids. On one hand, concentration of surfactant in the fluids has profound effects on their performance downhole. Additionally, there is continuous debate in the industry on whether the gel generated by these surfactants causes formation damage, especially in dry gas wells. Therefore, being able to analyze the concentration of these surfactants in both live and spent acids is of great importance for production engineers who apply surfactant-based fluids in the oil fields. In the present work, a two-phase titration method was optimized for quantitative analysis of a carboxybetaine viscoelastic surfactant, and surfactant retention in calcite cores was quantitatively determined by two phase titration method and the benefits of using mutual solvents to break the surfactant gel formed inside the cores was assessed. On the other hand, high temperatures and low pH are usually involved in surfactant applications. Surfactants are subjected to hydrolysis under such conditions due to the existence of a peptide bond (-CO-NH-) in their molecules, leading to alteration in the rheological properties of the acid. The impact of hydrolysis at high temperatures on the apparent viscosity of carboxybetaine viscoelastic surfactant-based acids was evaluated in the present study, and the mechanism of viscosity changes was determine by molecular dynamics (MD) simulations. Our results indicate that, first, significant amount of surfactant has been retained in the carbonate matrix after acidizing treatment and there is a need to use internal breakers when surfactant-based acids are used in dry gas wells or water injectors. Second, hydrolysis at high temperatures has great impact on surfactant-acid rheological properties. Short time viscosity build-up and effective gel break-down can be achieved if surfactant-acid treatments are carefully designed; otherwise, unexpected viscosity reduction and phase separation may occur, which will affect the outcome of acid treatments.