Summary Hydrochloric acid (HCl) is the acid of choice for acidizing operations in most carbonate formations, and is the base acid that is commonly paired with hydrofluoric acid (HF) in most sandstone applications. However, high dissolving power, high corrosion rate, lack of penetration, and sludging tendency coupled with high temperature (HT) can make HCl a poor choice. Alternatively, weaker and less-corrosive chemicals, such as organic acids, can be used instead of HCl to avoid these issues. The objective of this paper is to provide an intensive review on recent advancements, technology, and problems associated with organic acids. The paper focuses on formic, acetic, citric, and lactic acids. This review includes various laboratory evaluation tests and field cases that outline the use of organic acids for formation-damage removal and dissolution. Rotating-disk-apparatus (RDA) results were reviewed to determine the kinetics for acid dissolution of different minerals. Additional results were collected from solubility, corrosion, coreflooding, inductively coupled plasma, X-ray diffraction, and scanning-electron-microscope (SEM) diffraction tests. Because of their retardation performance, organic acids have been used along with mineral acids, mainly a formic/HCl mixture, or as a standalone solution for HT applications. However, the main drawback of these acids is the solubility of reaction-product salts. This challenge has been a limiting factor of using citric acid with calcium-rich formations because of the low solubility of calcium citrate. However, the solubility of the salts associated with formic, acetic, and lactic acid can be increased when these acids are mixed with gluconic acid because of the ability of gluconate ion to chelate calcium-based precipitation. In terms of formation-failure response, organic acids are in lower risk of causing a failure compared with HCl, specifically at deep formation treatments. Organic acids have also been used in other applications. For instance, formic acid is used in HT operations as an intensifier to reduce the corrosion rate caused by HCl. Formic, acetic, and lactic acids can be used to dissolve drilling-mud filter cakes. Citric acid is commonly used as an iron-sequestering agent. This paper shows organic acid advances, limitations, and applications in oil and gas operations, specifically in acidizing jobs. The paper differentiates and closes the gap between various organic acid applications along with providing researchers an intensive guide for present and future research.
Hydrochloric acid (HCl) is the acid of choice for acidizing operations in most carbonate formations and is the base acid commonly paired with others such as hydrofluoric (HF) in most sandstone applications. However, high dissolving power, high corrosion rate, lack of penetration, and sludging tendency coupled with high temperature can make HCl a poor choice. Alternatively, weaker and less corrosive chemicals such as organic acids can be used instead of HCl to avoid these issues. The objective of this paper is to provide an intensive review on recent advancements, technology, and problems associated with organic acids. The paper focuses on formic, acetic, citric, and lactic acids. This review includes various laboratory evaluation tests and field cases which outline the usage of organic acids for formation damage removal and dissolution. Rotating disk apparatus results were reviewed to determine the kinetics for acid dissolution of different minerals. Additional results were collected from solubility, corrosion, core-flooding, Inductively Coupled Plasma (ICP), X-Ray Diffraction (XRD), and Scanning Electron Microscope Diffraction (SEM) tests. Due to their retardation performance, organic acids have been used along with mineral acids or as a stand-alone solution for high-temperature applications. However, the main drawback of these acids is the solubility of reaction product salts. In terms of conducting dominant wormhole tests and low corrosion rating, organic acids with low concentrations show good results. Organic acids have also been utilized in other applications. For instance, formic acid is used as an intensifier to reduce the corrosion rate due to HCl in high-temperature operations. Acetic and lactic acids can be used to dissolve drilling mud filter cakes. Citric acid is commonly used as an iron sequestering agent. This paper shows organic acid advances, limitations, and applications in oil and gas operations, specifically, in acidizing jobs. The paper differentiates and closes the gap between various organic acid applications along with providing researchers an intensive guide for present and future research.
Calcium sulfate inorganic scale deposition is a major challenge that can block tubulars and hinder flow assurance during hydrocarbon production and water injection operations. This scale can form when high sulfate water gets in contact with water containing high content of calcium ions. Dissolving calcium sulfate is problematic due to its low solubility in water and common inorganic acids. Many scale dissolvers exist in the industry; however, the dissolving performance varies significantly when applied to calcium sulfate field samples. The main objective of this study is to evaluate the efficacy of three commercial calcium sulfate dissolvers for possible applications in the field. Field scale samples were characterized using X-ray diffraction and scanning electron microscopy with energy dispersive spectroscopy (XRD/SEM-EDS) to determine its composition. The HPHT aging cell was used to conduct the experiments at a temperature ranging from 77 to 300°F to evaluate the performance of several calcium sulfate dissolvers. The testing involved static dissolution tests to identify the optimal dissolver, scale dissolver to inorganic scale ratio, temperature influence, surface area influence, and the appropriate soaking time. Compatibility and thermal stability tests were also explored to avoid formation damage issues during the removal treatment. Additionally, corrosion tests were performed using low carbon steel metal coupons to assess the dissolver corrosivity at 200 and 300°F. The scale dissolvers compatibility and thermal stability were presented up to 300°F. The performance of the dissolvers generally increased as the temperature and soaking time increased. The scale dissolver chemistries were tested at high pH conditions and most of the tests exhibited a low corrosion rate of < 0.05 lb/ft2 with no significant pitting at 200°F or 300°F for the duration of the soaking time. One of the tested scale dissolvers failed the corrosion test at 300°F and two dissolvers thermally degraded when exposed to high temperature. This work is derived from testing actual inorganic scale field samples and shares the difficulty of dissolving such scale samples. The work also systematically compares three commercial scale dissolvers to resolve this issue.
Guar and its derivatives are the most commonly used gelling agents for fracturing fluids. At high temperature, higher polymer loadings are required to maintain sufficient viscosity for proper proppant carry and creating the fracture geometry. To minimize fracturing fluids damage and optimize fracture conductivity, it is necessary to design a fluid that is easy to clean up by ensuring proper breaking and sufficiently low surface tension for flow back. Therefore, breakers and surfactants must be carefully selected and optimally dosed to ensure the success of fracturing treatments. In this study, two fracturing fluids were evaluated for moderate to high temperature applications with a focus on post-treatment cleanup efficiency. The first is a guar-based fluid with a borate crosslinker evaluated at 280°F and the second is a CMHPG-based fluid with a zirconate crosslinker evaluated at 320°F. The shear viscosities of both fluids were tested with a live sodium bromate breaker, a polymer encapsulated ammonium persulfate breaker and a dual breaker system combining the two breakers. Different anionic and nonionic surfactant chemistries (aminosulfonic acid and alcohol based) were investigated by measuring surface tension of the surfactant solutions at different concentrations. The compatibility of the surfactants with other fracturing fluid additives and their adsorption in Berea sandstone was also investigated. Finally, the damage caused by leak-off for each fracturing fluid was simulated by using coreflooding experiments and Berea sandstone core plugs. Lab results showed the guar and CMHPG fluids maintained sufficient viscosity for the first two hours at baseline, respectively. The encapsulated breaker proved to be effective in delaying the breaking of the fracturing fluids. The dual breaker system was the most effective and the loading was optimized for each tested temperature to provide the desired viscosity profile. Two of the examined surfactants were effective in lowering surface tension (below 30 dyne/cm) and were stable for all tested temperatures. The guar broken fluid showed better regained permeability (up to 94%) when compared to the CMHPG (up to 53%) fluid for Berea sandstone. This paper outlines a methodical approach to selecting and optimizing fracturing fluid chemical additives for better post-treatment cleanup and subsequent well productivity.
Organic acids are commonly used to replace hydrochloric acid (HCl) in high reservoir temperature applications, as they are less corrosive and weaker than HCl. However, organic acids have shown some problems due to acid reaction product solubility. One such organic acid, lactic acid, produces calcium lactate when it reacts with calcite, which has a low solubility in water. However, reaction product solubility can be improved by up to five times when gluconate ions coexist with lactate and calcium ions. The objective of this research is to evaluate lactic and gluconic acid mixtures in term of dissolving calcite, reaction product, corrosion, wettability and generating dominant wormhole. Lactic and gluconic acids were mixed together using deionized water and seawater to conduct calcite solubility tests. Corrosion tests, between 4 and 8 hours, were also run under reservoir conditions. Zeta potential measurements were performed to determine alterations in rock wettability. A formation response test (FRT) apparatus was used to run different coreflood tests using different combinations of injection rates and temperatures. These tests were accompanied with analytical results from ICP and IC to measure calcium, iron and sulfate ions in solution. The results showed that mixing lactic and gluconic acids at a 1:1 molar ratio provided the optimal results as no precipitation occurred at total acids strengths of 10 wt% and up to 27 wt%. Seawater usage caused calcium sulfate precipitation; therefore, three scale inhibitors were evaluated to determine mitigation rates. Acid calcite-dissolving results were satisfactory when limestone was exposed to a 1:1 and 2:1 molar ratio of crushed core-to-acid ratios as at least 50% of the crushed core was dissolved. However, the two-acid mixture showed a corrosion rate that was higher than the acceptable rates and a trace of iron lactate precipitation occurred at 200 and 300°F. Five gpt from a sulfur-based corrosion inhibitor was enough to mitigate the corrosion rate to allow for eight hours of testing. Wettability alteration was noticeable due to the spent acid interaction with limestone rock and was the highest when high salinity seawater was used. Yet, the addition of corrosion inhibitor showed a reduction in the magnitude of zeta potential change. Coreflood tests showed that the mixture penetrated the tested core with minimal acid pore volume without any face dissolution or salt precipitation on the core faces. This research presents a set of diverse experimental data to confirm lactic acid accompanied by gluconic acid can penetrate carbonate formation without any by-product precipitation. The two organic acids are less corrosive and less hazardous which can provide a safe operation environment and can decrease replacement and maintenance costs.
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