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This includes identifying the acid optimum injection rate and volume, which leads to the minimum amount of acid required to achieve efficient wormhole propagation (Wang et al. 1993). Many factors influence the optimum acid-injection conditions (Hoefner and Fogler 1989; Wang 1993; Mostofizadeh and Economides 1994; Fredd and Fogler 1998, 1999; Shukla et al. 2006; Qiu et al. 2013; Xue et al. 2019). Previous laboratory studies have suggested that permeability, saturation, heterogeneity, core dimensions, temperature, and pressure can significantly affect the propagation of the wormholes and the optimum injection-rate value. We cover the range and conclusions from these studies and highlight the limitations, gaps, and inconsistencies in the results. Shukla et al. (2006) classified saturation conditions associated with matrix acidizing into four cases. The first case is when the acid job is performed after well completion, in which the saturation condition is either an irreducible water or a residual oil saturation, depending on whether the drilling mud used is oil-or water-based, respectively.
Summary Hydrochloric acid (HCl) is commonly used in acid fracturing. Given that the interaction between acid and rock affects multiphase flow behaviors, it is important to thoroughly understand the relevant phenomena. The Darcy-Brinkman-Stokes (DBS) method is most effective in describing the matrix-fracture system among the proposed models. This study aims to analyze the impact of acid-rock interaction on multiphase flow behavior by developing a pore-scale numerical model applying the DBS method. The new pore-scale model is developed based on OpenFOAM, an open-source platform for the prototyping of diverse flow mechanisms. The developed simulation model describes the fully coupled mass balance equation and the chemical reaction of carbonate acidizing in an advection‐diffusion regime. The volume of fluid (VOF) method is used to track the liquid- and gas-phase interface on fixed Eulerian grids. Here, the penalization method is applied to describe the wettability condition on immersed boundaries. The equations of saturation, concentration, and diffusion are solved successively, and the momentum equation is solved by pressure implicit with splitting of operators method. The simulation results of the developed numerical model have been validated with experimental results. Various injection velocities and the second Damkohler numbers have been examined to investigate their impacts on the CO2 bubble generation, evolving porosity, and rock surface area. We categorized the evolving carbon dioxide (CO2) distribution into three patterns in terms of the Damkohler number and the Péclet number. We also simulated a geometry model with multiple grains and a Darcy-scale model using the input parameters found from the pore-scale simulations. The newly developed pore-scale model provides the fundamental knowledge of physical and chemical phenomena of acid-rock interaction and their impact on acid transport. The modeling results describing mineral acidization will help us implement a practical fracturing project.
Summary The industry has been developing numerical models to simulate the wormholing phenomenon in carbonate matrix acidizing, both to save cost and time with experiments and to scale up the laboratory results to field scale. The two‐scale continuum model is a fundamental model that has been successfully used for this end. Previous studies with this model only simulated single‐phase flow: injection of acid into a water‐saturated rock. However, significantly different behavior is observed experimentally by injecting acid into oil‐ or gas‐saturated cores. In this work, we present a fundamental multiphase model for wormhole formation using the two‐scale continuum approach, allowing the simulation of wormholing for acid injection into oil‐ or gas‐bearing rocks, with different saturations. The two‐scale continuum model represents the fluid flow and acid transport in the porous medium at the Darcy scale but calculates the acid‐rock reaction with dissolution of the rock at the pore-scale. This model was implemented in transient 3D anisotropic form. Each phase occupies a volume fraction in each gridblock, defined by the porosity and fluid saturations. The fluid flow is calculated by solving the Darcy‐Brinkman‐Stokes equation, in which the relative permeabilities are functions of the saturations. The acid transport and reaction equations are solved, and as the acid injection proceeds and the rock is dissolved, the porosity increases in the gridblocks where dissolution occurs. The pore properties, such as permeability, pore radius, and specific surface area, are updated as porosity evolves, being scaled up from pore to Darcy scale. The simulation keeps track of the different fluid phases by calculating the saturations using the Implicit Pressure Explicit Saturation (IMPES) method. The developed model was implemented in an open-source computational fluid dynamics package and validated against experimental data. For the validation, the adjustable parameters in the model were calibrated so that the simulation results represent the different dissolution patterns and correctly reproduce the acid efficiency curves obtained experimentally. The same calibrated model was used to simulate the coreflooding experiments with water‐ and oil‐saturated cores. The dissolution patterns (face dissolution, conical wormhole, dominant wormhole, etc.) and acid efficiency curves predicted by the new model match the experimental data. Other simulations presented include the shift in the acid efficiency curves observed for different oil viscosities, residual oil saturations, and different water saturations. To our knowledge, this is the first 3D two‐scale continuum model to simulate wormhole propagation including multiphase flow. With adequate history match, it was shown to accurately predict the acidizing results for different fluid saturations, as observed in experiments.
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.
Various acids and chemicals have been developed to achieve retardation properties to enhance oil and gas production. Improving acid retardation through emulsification or polymer gelling agents has drawbacks. Retarded acid recipes including HCl, organic acids, and/or chemical retarders showed comparable retardation efficiency. This paper aims to compare the performance of non-viscous retarded acids and benchmark them against emulsified acids (
The proposed acid recipes are either a combination of HCl, formic acid with or without inorganic/organic retarders. Emulsified HCl acids at 15 wt% were prepared as a retardation baseline. Carbonate dissolution was assessed using solubility testing with calcite discs. Coreflood testing was conducted using Indiana limestone core plugs to assess the pore volume profile at temperatures up to 300 °F. This study was supported by Computed Tomography, to evaluate the propagation behavior as a result of the fluid/rock reaction.
The solubility calcite discs in the retarded acid recipes showed acid retardation comparable to emulsified acid. The surface tension values of retarded acid recipe were between 19.5-38.5 dynes/cm at 70-300°F. The coreflood results showed retardation performance comparable to emulsified acids at 200 and 300°F. The retarded recipes were capable to prevent nearly 1,500 mg Fe/L from precipitation in spent acid. The corrosion loss and pitting indices were within <0.02-0.09 lb/ft2 using retarded acid recipes at 170-300°F (i.e., <0.02-0.09). The optimum injection rates of retarded acid recipes were nearly 1 and 2 cm3/min at 200 and 300°F, respectively. The results obtained with HCl/Formic acid recipes showed generally competitive retardation performance compared to retarded acid recipes with limitations discussed in the paper.
Acidizing is a common stimulation treatment in carbonate reservoirs. Acid distribution over all layers and areas around a treated well is crucial for the matrix stimulation success. Effective acidizing, especially for long horizontal wells, requires acid diverting technique to insure uniform distribution along the wellbore intervals. Mechanical diversion is costly, while chemical diversion using in-situ gelled acid and viscoelastic surfactants have widely been applied during matrix stimulation. These chemical methods showed not only limited efficiency, but can introduce damage to the treated formation. Several chemical additives and complex formulations usually are used to ensure stability and success of diverting fluid application. This exercise greatly increases the treatment cost.
This study introduces a novel solution to improve acid diversion using in-situ foam generation. Thermochemical fluid is used to generate foam in-situ at downhole conditions, which will divert acid stages into not treated sections of the reservoirs. In this paper, two field treatments of two water injector wells, a vertical and a horizontal, were demonstrated using the new system. The in-situ foam generating fluid was used to divert acid in several pumping stages to ensure homogenous treatment. Pumping sequence and treatment mechanisms were described.
The results showed that in-situ foam generation approach has a very effective performance in diverting acid, with superior results compared to conventional diversion using viscoelastic surfactants. As the new system generates foam downhole, it showed very practical operation procedures. No pumping difficulties are experienced, compared with surface pumping to the foam. Having the reaction activated downhole, made the whole treatment safe and friendly to apply. Foam can occupy large areas, so less fluid is required to divert acid stage. Moreover, no complex formulation was required with several additives to ensure fluid activation downhole, which significantly reduced the overall treatment cost.
The novel method will enable effective and homogenous acidizing of carbonate reservoirs and eliminate the need for viscoelastic surfactants, which is expensive with limited effect. This work presents an effective method to place acid uniformly across a treated well using in-situ foam generation.
A paper presents results of an industrial application of an innovative technology for oil and gas producing wells stimulation. Also, research results of a laboratory study of ESN (emulsion system with supercharged nanoparticles) physical and chemical properties under atmospheric and modeled reservoir conditions are briefly described in this paper. The technology is based on the use of an innovative emulsion system with supercharged nanoparticles (ESN) as a solution to solve two tasks at once: 1. to divert an active composition injected after; 2. to block water bearing most-permeable zones within a profile of productive interval for more than 12 months. The case studies considered in this paper focused on the technology application in two mature carbonate formations of Ural-Volga oil-gas province located in Russia. The formations have been under industrial development for almost 50 years and characterized by complicated geology and deteriorated reserves. A combination of effects of diverter and water-blocking agent, in one composition, provides significant competitive advantages, which resulted in two times increase in oil rates with a decrease in water cut of treated by the technology oil-gas producing wells. A duration of positive effect reached 14 months on average for ten treated wells, which is four times higher than a classical acidizing technology applied on the same formations. The main competitive advantages of the technology are enlarged surface charge (alteration of wettability of rock), high thermal stability (150 °C), predictable rheology (Herschel-Balkly model), reversible blocking effect and absence of negative impact on geological formation, downhole equipment and oil and gas collecting system (environmental friendly).
Abstract Hydrochloric acid is commonly used in acid fracturing. Given that the interaction between acid and rock affects multiphase flow behaviors, it’s important to thoroughly understand the relevant phenomena. Darcy–Brinkman–Stokes (DBS) method is most effective to describe the matrix–fracture system among the proposed models. The objective of this study is to analyze the impact of acid–rock interaction on multiphase flow behavior, by developing a pore–scale numerical model applying DBS method. The new pore–scale model is developed based on OpenFOAM, which is an open source platform for the prototyping of diverse flow mechanisms. The developed simulation model describes the fully–coupled mass balance equation and the chemical reaction of carbonate acidization in an advection–diffusion regime. Volume of Fluid (VOF) method is employed to track liquid and gas phase interface on fixed Eulerian grids. Here, penalization method is applied to describe the wettability condition on immersed boundaries. To compute the numerical solutions of discretized equations, finite volume method is applied, where the equations of saturation, concentration, and diffusion are solved successively, and momentum equation is solved by using Pressure–Implicit with Splitting of Operators (PISO) method, respectively. The simulation results computed by this numerical model have been validated by experimental results. Different injection velocities and the second Damkohler numbers have been simulated to investigate their effects on the evolving porosity and rock surface area. The newly developed pore–scale model in this research provides the fundamental knowledge of physical–and–chemical phenomena of acid–rock interaction and their impact on acid transport. The modelling results describing mineral aci dization will help us to implement an effective fracturing project while reducing environment impacts.
Hydrochloric acid is commonly used in acid fracturing. Given that the interaction between acid and rock affects multiphase flow behaviors, it’s important to thoroughly understand the relevant phenomena. Darcy–Brinkman–Stokes (DBS) method is most effective to describe the matrix–fracture system among the proposed models. The objective of this study is to analyze the impact of acid–rock interaction on multiphase flow behavior, by developing a pore–scale numerical model applying DBS method. The new pore–scale model is developed based on OpenFOAM, which is an open source platform for the prototyping of diverse flow mechanisms. The developed simulation model describes the fully–coupled mass balance equation and the chemical reaction of carbonate acidization in an advection–diffusion regime. Volume of Fluid (VOF) method is employed to track liquid and gas phase interface on fixed Eulerian grids. Here, penalization method is applied to describe the wettability condition on immersed boundaries. To compute the numerical solutions of discretized equations, finite volume method is applied, where the equations of saturation, concentration, and diffusion are solved successively, and momentum equation is solved by using Pressure–Implicit with Splitting of Operators (PISO) method, respectively. The simulation results computed by this numerical model have been validated by experimental results. Different injection velocities and the second Damkohler numbers have been simulated to investigate their effects on the evolving porosity and rock surface area. The newly developed pore–scale model in this research provides the fundamental knowledge of physical–and–chemical phenomena of acid–rock interaction and their impact on acid transport. The modelling results describing mineral aci dization will help us to implement an effective fracturing project while reducing environment impacts.
Abstract 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.