Acidizing in sandstone formations is a real challenge for the industry. Fines migration, sand production, and additional damages due to precipitation are some of the common concerns with sandstone treatments. Furthermore, the complexities of sandstone formations require a mixture of acids and loadings of many additives. The environmentally friendly chelating agent, glutamic acid N,N-diacetic acid, GLDA, was successfully used to stimulate deep gas wells in carbonate reservoirs. It was extensively tested in the lab to stimulate sandstone cores with various mineralogies. Significant permeability improvements were reported in our previous papers over a wide range of conditions. In this paper, we evaluate the results of the first field application with a fluid based on this chelating agent to acidize an offshore, sour oil well in a sandstone reservoir. The field treatment included pumping a preflush of xylene to remove oil residues and any possible asphaltene deposited in the wellbore area, followed by the main stage that contained 25 wt% GLDA, a corrosion inhibitor, and a water wetting surfactant. The treatment fluids were displaced into the formation by pumping diesel. Following the treatment, the treatment fluids were allowed to soak for 6 hours, then the well was put on production, and samples of flowback fluids were collected. The concentrations of key cations were determined using ICP, and the chelate concentration was measured utilizing a titration method using ferric chloride solutions. Corrosion tests conducted on low carbon steel tubulars indicated that this chelate has low corrosion rates under bottomhole conditions. No inhibitor intensifier was needed. The treatment was applied in the field without encountering any operational problems. A significant gain in oil production was achieved without adversely impacting the water cut, causing sand production, or fines migration. Analysis of flowback samples confirmed the ability of the chelating agent solution to dissolve various types of carbonates, oxides, and sulfides, while keeping the dissolved species in solution without causing unwanted precipitation. Unlike previous treatments conducted on this well, where 15 wt% HCl or 13.5/1.5 HCL/HF acids were used, the concentrations of iron and manganese in the flowback samples were negligible, confirming the very low corrosion rates of well tubulars when using GLDA solutions.

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 acid, especially at high temperatures. In this study, formic acid was used to remove carbonate minerals as a preflush and with the main HF stage. A series of formic acid and HF mixtures with different ratios and concentrations were tested. Sandstone cores featured by different minerologies with dimensions of 1.5 in. x 6 in. were used in the coreflood experiments, which were run at a flow rate of 5 cm 3 /min and temperatures from 77 to 350°F. The cores were analyzed by CT scan before and after the acidizing to investigate the effect of the acid. The core effluent samples were analyzed to determine concentrations of Ca, Mg, Fe, Si, and Al by ICP. 19 F NMR was utilized to follow the reaction kinetics and products. Zeta potentials of clay particles (kaolinite, illite, and chlorite) were measured in various acid solutions Formic acid (9 wt%) damaged sandstone cores. Zeta potential measurements indicated that formic acid can trigger fines flocculation. Addition of 5 wt% ammonium chloride helps to shield negative charges on clay surface. Analysis of core effluent samples indicated that there was CaF 2 precipitate in the core when a small volume of preflush was used. Coreflood tests highlighted that formic acid/HF caused loss of core permeability. This paper will discuss the detailed chemical reactions occurred within cores and were followed by chemical analysis of core effluent samples and 19 F NMR. Secondary reaction between clay minerals and HF became faster at higher temperature, and decreased the ratio of Si/Al. It was also found that different clay minerals react with HF offering very different concentrations of Al and Si in spent acid.

The present work investigates the impact of high temperature on fines migration and is useful for both sandstone and shale formations at high temperatures. The results show subsequent loss of permeability in clay-containing rocks such as sandstone. Three types of clays are present in sandstone rock used for experiments: kaolinite, illite, and chlorite. Both experimental and theoretical results of conducted coreflood experiments show that the rise in temperature sensitizes fines, and thus decreases sandstone permeability significantly upon the injection of fresh water. Coreflood experiments were performed at 74, 200, and 300°F temperatures. Brine, 5 wt% NaCl was injected at room temperature to determine the initial rock permeability. Next, temperature was applied to the system, and various potential clay stabilizing salts, as well as fresh water flooding, was performed in both forward and reverse directions to confirm plugging. Core effluent was collected during each experiment and analyzed to measure the concentration of key cations using ICP-OES. The experimental results were verified by application of the DLVO theory. The mathematical model was used to evaluate the magnitude and determine the effect of each of the contributing forces. The results show that the double layer repulsion force has the most significant impact, due to change in temperature of the matrix-clay system. Based on the results attained, it can be concluded that fines migration is a serious problem in sandstone formations at high temperatures. High salt concentrations or salts containing high valency cations will be required to mitigate fines migration due to pH changes at higher temperatures. From experimental results obtained, 15 wt% NaCl and 15 wt% HCl solutions were able to preserve permeability in the rock and minimize fines migration at elevated temperatures. This paper will discuss experimental and theoretical studies conducted that highlight the importance of fines migration in hightemperature wells.

Acid treatments in high temperature deep wells drilled in carbonate reservoirs represent a challenge to the oil industry. The high temperature of deep wells requires a special formulation of emulsified acid that can be stable and effective at such high temperatures. At these high temperatures, both the reaction rate between acid and rock, and corrosion rate of tubulars are high. This fact makes protection of tubulars and reducing the reaction rate between rock and acid challenging. At temperatures above 200 °F, there is a need to add more corrosion inhibitor and corrosion inhibitor intensifier, which increases the cost of the treatment too much. A new emulsifier was developed and used to prepare emulsified acids that can be used in stimulating deep wells drilled in carbonate reservoirs. In the present paper, the rheology of the new acid is compared to the rheology of another system formulated by a commercial emulsifier that has been used extensively in the field. All emulsified acid systems were formulated at 0.7 acid volume fraction, and the final HCl concentration varied from 5 to 28 wt% HCl. The rheology measurements were conducted at temperatures up to 300 °F for emulsifier concentration ranges from 0.5 to 2.0 vol%. The reaction between emulsified acid and rock was studied using a rotating disk apparatus at 230 °F and rotation speeds up to 1,500 rpm. A core flood study was conducted in order to study the efficiency of the new emulsified acid to create wormhole, and increase the efficiency of the treatment, especially at a high temperature (300 °F). The results showed that the new emulsified acid system had higher thermal stability and higher viscosity than the old one. Also, the new emulsified acid system created deep wormholes at all injection rates covered (0.1 cm 3 /min up to 10 cm 3 /min), with no face dissolution encountered during acid injection. The reaction rate between emulsified acids formulated using the new emulsifier was measured using a rotating disk at 230 °F. The dissolution rate varied between 2.57E-6 gmol/cm 2 .s at 100 rpm and 1.09E-5 gmol/cm 2 .s at 1500 rpm. The diffusion rate was measured for these emulsified acid systems and was found to be around 2.73E-7 cm 2 /s. From these results, the new emulsifier can be used in formulating emulsified acid systems that can be used effectively in stimulation of high temperature deep wells. This paper summarizes the results of testing the new emulsified system, and recommends its use for field application in deep carbonate reservoir.

Acid-in-diesel emulsified acid has been used in the oilfield for many years. Emulsified acid systems are retarded systems that can be used effectively in stimulation of carbonate reservoirs. Emulsified acids have primarily been used in acid fracturing and matrix acidizing. The delayed nature of emulsified acids is useful in generating longer etched fractures or deeper wormholes. To predict the penetration depth of wormholes or the length obtained from an acid fracturing treatment, diffusion coefficient values need to be estimated. This paper discusses the rheology, and reaction kinetics of emulsified acids formulated using a new emulsifier. The emulsified acid systems were prepared at 15 wt% HCl and 0.7 acid volume fraction. Emulsifier concentration was varied from 0.5 to 2.0 vol%. For all emulsions, viscosity was measured using an HPHT rheometer. Emulsified acid reaction rates, and hence acid diffusivity, were measured using a rotating disk apparatus at a temperature of 230 °F. Disk rotational speeds were varied from 100 to 1,500 rev/min. Samples of the reacted acid, from the reactor, were collected and analyzed using the Inductively Coupled Plasma, to measure calcium and magnesium concentrations. Rheological measurements indicated that emulsified acid systems behaved as a non-Newtonian shear-thinning fluid, and this behavior can be represented by a power law model. The emulsifier concentration and temperature affect greatly the viscosity of emulsified acids. The new emulsified acid systems achieved low reaction and diffusion rates; as the emulsifier concentration increased, both reaction and diffusion rates decreased. Emulsified acid –dolomite reaction was mass transfer limited at low emulsifier concentration. The behavior was in the middle region between mass transfer limited and surface reaction limited for higher emulsifier concentrations. At high emulsifier concentration, the reaction appears to be surface reaction limited. These results can be used to optimize the design of carbonate acidizing treatments using emulsified acid.

CO 2 injection in carbonate formations causes a reduction in the well injectivity, due to precipitation of the reaction products between CO 2 / rock/brine. The precipitated material includes sulfate and carbonate scales. The homogeneity of the carbonate rock, in terms of mineralogy and rock structure, is an important factor that affects the behavior of permeability changes during CO 2 injection. Limestone rocks represent the homogenous rock in this study, and include: Pink Desert limestone and Austin chalk, which are mainly calcite. Silurian dolomite (composed of 98% carbonate minerals, and 2% silicate minerals) and Indiana limestone rock represent the heterogeneous rock, which have some vugs in their structure. Coreflood experiments were conducted to compare the behavior of the permeability loss between these rocks. CO 2 was injected with the water alternating gas (WAG) technique. Different brines were examined including seawater and no sulfate seawater. The experiments were run at a pressure of 1300 psi, a temperature of 200°F, and an injection rate of 5 cm 3 /min. A compositional simulator tool (CMG-GEM) was used to confirm the experimental results obtained in this study. The results showed that for homogenous rocks, the presence of sodium sulfate in the injected seawater is the major factor that causes formation damage, due to calcium sulfate precipitation in CO2 environments. For dolomite rocks, higher damage was noted, due to the reactions of CO 2 with the silicate minerals. For both homogenous and heterogeneous rocks, the source of damage for high permeability cores is the precipitation of reaction products, while for low permeability cores, water blockage increases the severity of formation damage. The simulation study showed that the power-law exponent, and Carman-Kozeny exponent between 5 and 6, can be used for homogenous carbonate rock to estimate the change in permeability based on the change in porosity, for heterogeneous rock a larger exponent was needed.

The damaging effect of calcium sulfate precipitation on the permeability of carbonate cores when mixing hydrochloric acid with seawater for matrix acid treatments has been identified in our recent work (SPE 143855). The objective of this work is to mitigate calcium sulfate precipitation by using a suitable scale inhibitor in hydrochloric acid. Another objective is to determine the scale inhibitor type, concentration, and whether it is needed in the preflush or post-flush stages. Core flood tests were conducted using Austin Chalk cores(1.5 in. × 6 in.) with a permeability of 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. The minimum concentration of scale inhibitor was determined over a wide range of temperatures (77 to 210°F). A scale inhibitor (sulfonated terpolymer) was found to be compatible with hydrochloric acid systems, and can tolerate high concentrations of calcium (30,000 mg/l). Analysis of the 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 that an appropriate scale inhibitor can be added to acid, to avoid calcium sulfate precipitation when seawater is used to prepare hydrochloric acid for matrix acidizing.

Matrix acidizing is used in carbonate formations to create wormholes that connect the formation to the wellbore. Hydrochloric acid, organic acids, or mixtures of these acids are typically used in matrix acidizing treatments of carbonate reservoirs. However, the use of these acids in deep wells has some major drawbacks including high and uncontrolled reaction rate and corrosion to well tubulars, especially those made of chrome-based tubulars (Cr-13 and duplex steel), and these problems become severe at high temperatures. To overcome problems associated with strong acids, chelating agents were introduced and used in the field. However, major concerns with most of these chemicals are their limited dissolving power and negative environmental impact. Glutamic acid diacetic acid (GLDA) a newly developed environmentally friendly chelate was examined as a replacement for acid treatments in deep oil and gas wells. The solubility of calcium carbonate in the new chelate was measured over a wide range of parameters. Core flood tests were conducted using long Indiana limestone cores 1.5-inch in diameter and 20 inches in length, which allowed us to better understand the propagation of this chemical in carbonate rocks. The cores were scanned with X-ray before and after the injection of chelate solutions into the cores. The concentration of calcium and chelate were measured in the core effluent. To the best of our knowledge, this is the first study to examine the fate and propagation of chelating agents in coreflood studies. GLDA has a very good ability to dissolve calcium from carbonate rocks over a wide pH range by a combination of acid dissolution and chelation. The addition of 5 wt% sodium chloride did not affect the GLDA performance at pH= 13, but significantly accelerated the reaction at pH= 1.7. Compared to other chelating agents, GLDA dissolved more calcium than EDG but less than HEDTA at high pH values. GLDA of pH = 1.7 was able to form wormholes at 2 and 3 cm 3 /min. GLDA was found to be thermally stable at temperatures up to 350°F

The purpose of matrix stimulation in carbonate reservoirs is to bypass the damaged zones and increase the effective wellbore area. This can be achieved by creating highly conductive flow channels known as wormholes. A further injection of acid will follow the wormhole path where the permeability has increased significantly, leaving substantial intervals untreated. This problem can be significant as the contrast in permeability increases within the target zones. Diverting materials such as surfactant-based acids play an important role in mitigating this problem. Several papers published in the literature aimed to verify the diversion capability and the performance of the self-diverting acids. However, most of the parallel-coreflood experiments, if not all, used relatively short cores (2 to 6 inches in length). In this paper, acidizing experiments were conducted using two 20-inch long cores with different permeabilities. Carbonate cores were used with a permeability of 5 to 150 md and the total flow rate was varied from 3 to 20 cm 3 /min. The initial contrasts in permeability between the two cores ranged from 2 to 15 fold. To characterize the wormholes generated, a computerized tomography (CT) was used to generate 3-D images to describe the shape of the wormholes in both cores. Several periods were identified from the shape of the flow rate distribution entering each core. Acid injection rate was found to influence the efficiency of surfactant to divert acid. Acid diversion was noted to be most efficient at low flow rates (3 cm 3 /min). No significant diversion was noted at higher flow rates (> 6 cm 3 /min). Also, no significant diversion was noted at high initial permeability ratios at least for the given core length. In conjunction with the experimental study, an analytical model was developed to verify the experimental results obtained with regular acids.

Viscoelastic surfactants have been applied extensively in the field, because of their unique characteristics of forming rod-like micelles with the increase of pH and calcium concentration. There is continuous debate in the industry on whether the gel generated by these surfactants causes formation damage or not. This is especially true in dry gas wells. The objective of the present study is to conduct core flood experiments using surfactant-based acids and measure the concentration of the surfactant concentration in the core effluent. Material balance on the surfactant will shed lights on the amount of surfactant recovered, which will help in assessing damage due to surfactant gel retention in the cores. Core flood tests were performed using calcium carbonate cores 1.5 in. diameter and 20 in. length. The cores were injected with a surfactant-based acid of 15 wt% HCl that contained 7 vol% surfactant and other acid additives. Core flood test were conducted at constant injection flow rate that was varied from 3 to 40 cm 3 /min. Carbonate cores of various initial permeability were used. In all core tests, surfactant concentration was measured in the injected acid and core effluent using the two-phase titration method. Mutual solvent was used to break surfactant gels. Considerable amounts of viscoelastic surfactant were retained in the carbonate cores after the acid treatments, and the retained surfactant gel is a source of formation damage if not effectively removed. The amount of surfactant-based acid required to create wormhole in carbonate matrix is high at both low shear rate (< 900 s -1 ) and high shear rate (> 3,000 s -1 ), and is low at intermediate shear rates with the minimum value at shear rate of 1,500 to 2,000 s -1 . The surfactant retention in the carbonate matrix is lowest at shear rates near 2,000 s -1 , and is high at both high and low shear rates. Surfactant was retained in gelled form. Mutual solvent was able to remove as much as 21% of the total amount of surfactant injected into the core.

While experimental studies have shown acid type significantly influences resulting fracture conductivity, there has been limited work on how fluid properties relate to etched fracture faces and hence the resulting conductivity. The effects of acid solutions injected into hydraulic fractures created in carbonate formations can be assessed at the laboratory scale in acid fracture conductivity tests that mimic the conditions in an actual acid fracture treatment. Many different acid systems are currently applied in acid fracturing treatments with various degrees of success. However, there is no clear understanding of the mechanisms that lead to success of a treatment. It is clear that acid properties influence and shape the success of an acid fracturing treatment. In order to develop a better methodology for design of acid fracturing treatments, the effect of acid fluid properties on the resulting conductivity and etching must be determined. A series of acid fracture conductivity tests was conducted using four commonly used acid fracturing fluids—gelled, in-situ gelled, emulsified, surfactant-based acid. Detailed rheological properties were measured in order to explain trends noted with conductivity data. Acid system influences the degree of etching and the etching pattern due to differences in chemical and physical properties of acid systems. Under our experimental conditions, viscoelastic acid generated the greatest degree of etching and best etching pattern. Majority of experiments showed differences in conductivity among acid systems tested with most optimal acid system depending on the closure stress. While viscoelastic acid generated the highest conductivity at low closure stress, emulsified acid resulted in the largest retained conductivity at higher loads for our experimental conditions. Furthermore, effluent analysis on both the leakoff and fracture flow showed that most of the fracture face etching is the result of leaked acid into the formation with minimal etching from the fracture flow acid.

Surfactant-based acids have been used for acid diversion because they are less damaging to the formation. Amphoteric viscoelastic surfactant is the main type of surfactants being used today. Low viscosity is observed in the live acid systems, whereas significantly increased viscosity is found when HCl reacts with carbonate and generates divalent salts. The surfactant-acid system can be broken after acid treatments by mixing with reservoir hydrocarbons, or by using an external or internal breaker. Amidoamine oxide, an amphoteric surfactant, was examined in this work. The prepared surfactant-based live acid system contained 20 wt% HCl, 4 wt% surfactant and 1 wt% corrosion inhibitor. Different organic acids/chelating agents were added to live and spent acids. Calcium carbonate particles were used to neutralize live acids. The objective was to examine how these organic acids/chelating agents affected the rheological properties of spent acid systems. Measurements were made at temperatures from 75 to 200 °F, at a shear rate of 10 s -1 at 300 psi. Several simple organic acids (formic acid, acetic acid, propionic acid, and butyric acid), chelating agents (glycolic acid, lactic acid, gluconic acid, citric acid, tetrasodium EDTA, tetrasodium GLDA and disodium HEIDA) that are used in the field were examined. Experimental results indicated that the addition of organic acid/chelating agents significantly reduced the viscosity of spent acids. This reduction in viscosity increased with the number of carbon atoms in the acid. The addition of organic acids reduced the temperature range where the surfactant can be used. Chelating agents (α-hydroxyl carboxylic acids and amino acids) also tended to break the surfactant gel if enough acid was used. Based on the results obtained, organic acids can be used to break surfactant gel. TEM tests were first conducted to examine how organic acids/chelating agents interfered with the formation of rod-like micelles in the surfactant-based acid. The results showed that the addition of organic acids to the spent acid generated less elongated micelle structures and resulted in less apparent viscosity. In addition, if chelating agents or simple organic acids are used, then the concentration of the surfactant should be increased to compensate for the loss of viscosity induced by the addition of the organic acids.