Acid-rock Reaction Research Articles

Non-isothermal simulation of wormhole propagation in fractured carbonate rocks based on 3D-EDFM

The current models of fractured carbonate acidizing are limited to 2D simulation or are solely applicable to the acidizing process in porous media with few fractures, neglecting the acid flow between intersecting fractures. In response to these issues, a coupled 3D thermal-hydro-chemical 3D-EDFM method is developed to simulate the acidizing process in fractured carbonate rock. The fractured carbonate acidizing model is coupled by 3D-EDFM, the two-scale continuum model and the heat transfer model in this paper. Numerical simulations of acidizing under different temperatures are performed, and the simulation results are consistent with previous experimental findings, thus verifying the accuracy of the model. Through simulations, we found that as the flow rate increases, the fracture plane transitions from acting as a “dissolution object of acid” to serving as a “transport channel of acid”. The density and inclination angle of the fracture plane significantly affect the wormholes propagation. The presence of fracture planes accelerates the pressure drop during acidizing and complicates the distribution of the acid-rock reaction heat. Unlike in the 2D model, we observe that when cold acid is injected into high-temperature fractured carbonate rock, the acid cools the rock from the inside out. Although higher rock temperatures lead to an increase in , the difference in the optimum injection rate remains minimal. Compared to porous media without fracture planes, the fracture plane increases the optimum injection rate, and appropriately increasing the injection rate can more effectively utilize the transport characteristics of natural fractures.

Evolution characteristic and mechanism of microstructure, hydraulic and mechanical behaviors of sandstone treated by acid-rock reaction: Application of in-situ leaching of uranium deposits

The main difficulty in understanding the effects of chemical-physical composite stimulation for low-permeability sandstone-type uranium deposits is clarifying the influence of acidification on pore response mechanism and permeability-mechanical properties evolution during loading-deformation-failure process. Therefore, the acid-rock reaction experiment was first performed, the multiple testing methods (X-ray Diffraction, thin-section identification, high-pressure mercury intrusion porosimetry, stress-seepage coupling experiment) were then conducted, the evolution laws and mechanisms of reservoir physical characteristics after acidification were finally clarified. Results show that after the acid-rock reaction, the contents of calcite, feldspar and kaolinite of samples are decreased and the quartz content is increased, the permeabilities of samples are all promoted, the peak strength, elastic modulus, and shear modulus of samples are reduced and the Poisson’s ratio is raised. The acid-rock reaction changes the energy storage performance and promotes the plasticization of samples. It is suggested to adopt a lower sulfuric acid concentration (2 g/L) and longer reaction time (>45 d) for the ISL of uranium deposits. This work has important theoretical and practical significance for an in-depth understanding of the enhanced mining of low-permeability sandstone-type uranium deposits.

Effect of two-phase viscosity difference and natural fractures on the wormhole morphology formed by two-phase acidizing with self-diverting acid in carbonate rocks

Different types of acids are needed in the field to achieve various acidizing goals. Currently, there are no reliable acidizing models for multiphase flows and complex multiphysics coupling. This paper derives mathematical formulas for the oil–water acidizing process of a situ self-diverting acid combined with thermal–chemical–fracture interactions and discusses the influence of two-phase oil–water mixture and fractures on the wormhole morphology produced by self-diverting acid. The results show that the spent acid following the acid–rock reaction forms a high-viscosity sealing zone, causing the injected acid to be redirected. The self-diverting acid forms more numerous and longer branches than a conventional acid during single-phase acidizing. In the case of two-phase acidizing, the high viscosity difference produces distinct effects when using self-diverting acid compared with conventional acid. Specifically, the self-diverting acid extends the breakthrough time and forms a wormhole morphology with longer and more complex branches, whereas the conventional acid accelerates the breakthrough of the rock. As the viscosity difference decreases, the wormhole morphology of the self-diverting acid gradually approaches that of a single-phase acid. Large-aperture fractures completely determine the wormhole morphology, while smaller apertures determine the branch morphology of the wormhole. Fractures have a negative acidizing effect in the case of the self-diverting acid, unlike conventional acid. The proposed model accurately simulates the complex acidizing process of a self-diverting acid.

Effects of functional groups in polymers on rate of acid–rock reaction in reservoir stimulation

The focus of research on acid stimulation is to reduce the rate of the acid–rock reaction, which involves the infiltration of acid into deep formations. Gelled acids with high viscosity can decelerate the diffusion of hydrogen ions to decrease the rate of the acid–rock reaction. However, there have been few reports on the interactions between functional groups in polymers and rocks. In this study, three polymers (AA7, AA24, and AAS) with different functional groups were synthesized, and their effects on the acid–rock reaction were investigated. The results showed that the order of the abilities of the three polymers to delay the acid–rock reaction was as follows: AA24 > AA7 > AAS. The retardation rate for AA24, AA7, and AAS was 79.31%, 66.67%, and 40.23%, respectively. Adsorption experiments illustrated that AA7 and AA24 were adsorbed on the surface of calcite via hydrogen bonds formed by ethoxy groups, whereas AAS relied on the hydrophobic effect of the benzene ring. The anionic polymer AAS was subjected to a strong electrostatic effect in an acid solution, which caused the molecular chains to curl and impaired the retarding performance. This was proved by the fact that the viscosity dramatically decreased from 66.00 mPa s in an aqueous solution to 7.50 mPa s in an acid solution and the effective diameter decreased from 322.2 nm in an aqueous solution to 102.2 nm in an acid solution. In the cases of the nonionic polymers AA7 and AA24, there was little change in viscosity or effective diameter, whether in an acid solution or an aqueous solution. Scanning electron microscopy confirmed that the film formed by the adsorption of AA24 on the surface of calcite was denser than that formed by AA7 because more ethoxy groups were present in AA24, but the film exhibited some narrow cracks in the case of AAS. Atomic force microscopy demonstrated that the surface roughness of calcite etched by a retarding acid solution of AA24 was only 78 nm, whereas it was as high as 130 nm in the case of AAS, which was consistent with the retarding performance with regard to the acid–rock reaction. This research could contribute to improvements in carbonate acidizing for reservoir stimulation.

Optimization and evaluation of corrosion inhibitors for N80 steel in sulfamic acid solutions

Sulfamic acid (SA) has a low acid-rock reaction rate and can be used for deep high-temperature acidizing. However, the inhibition effect of existing corrosion inhibitors at deep high temperatures is greatly reduced. Through experiments, it is found that corrosion inhibitors such as imidazoline (OAI), cinnamaldehyde (CA), C14 quaternary ammonium salt (C14-GN), and potassium iodide (KI) have good corrosion inhibition effect, the average corrosion inhibition rate can reach 99 %, and the corrosion rate is less than 2 g/m2 h. The experimental results show that the film formation of a single inhibitor is uneven and the pitting corrosion is serious. In contrast, the mixed-use of many kinds of inhibitors can effectively inhibit the pitting corrosion, and the corrosion rate is less than 1.6 g/m2 h. And it can effectively inhibit pitting corrosion. At 363 K, the corrosion inhibition rate is 99.9 % and the corrosion rate is 1.1 g/m2·h. Through the orthogonal test, it is concluded that the best inhibitor ratio is OAI: CA: C14-GN: KI = 3:3:3:2. The optimized inhibitor has the best synergistic effect, can play an important role at high temperature, make the film uniform and dense, and improve the corrosion inhibition effect of the solution of sulfamic acid with the investigated inhibitor.

Anisotropy of surface morphology of carbonate rocks after reaction with acid

In acid fracturing, acid is injected into artificial fracture to dissolve the rock, and the rock surface is shaped into the non-uniform morphology. This non-uniform morphology is the main cause of fracture conductivity after acid etching. The effects of acid type, flow rate, contact time and rock type on the non-uniform morphology of acid-etched rock surface have been studied. However, when the direction of acid flow is determined, the difference of dissolution characteristics in different directions of rock surface is not investigated. In this paper, acid rock reaction experiment and analysis of rock surface morphology after acid etching are carried out by using rock samples with flat surface. The difference of morphological characteristic parameters of rock surface in different directions under the condition of acid flow is discussed. It was found that the mean drop height, drop height range and roughness coefficient increase with the increase of acid rock reaction rate on flat rock surface. The morphological characteristic parameters of acid-etched rock face of limestone are greater than those of dolomite, which is conducive to forming acid-etched channels. According to the statistics of all experimental data, the larger average drop height of rock surface is distributed in the direction of parallel acid flow, the larger drop height range is distributed in the direction of vertical acid flow and other directions, and the larger roughness coefficient is distributed in other directions.

Study on the effect of natural fractures and temperature on the wormhole morphology formed by two-phase acidizing in carbonate rocks

The simulation of a two-phase acidizing process coupled with thermal–chemical–fracturing is a complex task, given the presence of natural fractures in carbonate rocks and the influence of temperature on the acid–rock reaction. In this work, we introduce a mixed computational strategy combining the operator splitting and the Newton iteration built upon the embedded discrete fracture model. This innovative strategy is designed to tackle nonlinear problems arising from the coupling of multiphysics fields. The porosity improved region within rock is divided into three parts: the high (H), medium (M), and low (L) efficiency regions, aimed at clearly assessing the impact of various physical fields on acidizing efficiency. The results show that the wormhole morphology is determined by the H and M regions, and the L region determines the acidizing efficiency. The oil in the rock can have a “sealing effect” on the acid, improving the acidizing efficiency. For the large fracture aperture, the wormhole morphology is predominantly influenced by fractures, with the influence diminishing as the aperture decreases. At small apertures, fractures exhibit minimal impact on the morphology. While increasing injection temperature may not significantly alter the wormhole morphology, it can enhance acidizing efficiency. The morphology of wormholes is highly sensitive to multiphase interactions, fractures, and temperature variations. The proposed hybrid computational strategy effectively addresses multiphysics field challenges in two-phase acidizing.

Pore-Scale Numerical Simulation of Acid-Rock Reaction Processes in Carbonate Reservoirs.

In the process of acidizing carbonate reservoirs, dissolution is employed for reservoir modification to enhance recovery rates. This study establishes a numerical model at the pore scale for acid-rock reaction flow based on a microscopic continuum medium model, integrating phase-field theory and component transport models. Subsequently, the results of the Darcy-Brinkman-Stokes model are compared to those of the arbitrary Lagrange-Euler method to validate the accuracy of the model. Finally, the flow behavior of the acid solution at the pore scale and the complex dissolution mechanisms in carbonate reservoirs are analyzed. The research indicates that the microscopic pore-scale dissolution in carbonate reservoirs mainly manifests as five dissolution modes: uniform dissolution, compact dissolution, conical wormholes, dominant wormhole, and ramified wormholes. Different distributions of microfractures will alter the flow state of the acid solution and the rock-acid reaction process within the pores. Once the wormhole breakthrough occurs, there is an increased probability of acid flow through the wormhole to the outlet, leading to a decrease in the effectiveness of the acidizing carbonate reservoirs. A proper understanding of pore-scale acid-rock reaction laws is of great significance for the development of carbonate oil and gas reservoirs.

Optimizing acid microemulsions for cleaner gas production: A study on enhanced adsorption characteristics and implications in retardation

The ultralow interfacial tension between the oil and aqueous phases and the solubilization characteristics in microemulsion systems make them useful for surface cleaning and enhanced oil recovery applications. Microemulsions can form an adsorbed barrier on rock, reducing the acid-rock reaction rate. However, as acid retardation additives, the adsorption patterns of microemulsions are not clearly defined. In this study, microemulsions composed of various electrical surfactants, oil cores, and oil core additives were obtained, and their phase behaviors were investigated. Through adsorption and reaction experiments, cleaning microemulsions that enhance adsorption effects were identified, and their adsorption patterns and adaptability under flow conditions were evaluated. The results demonstrate that incorporating negatively charged polar compounds forms an enhanced adsorption microemulsion characterized by an average droplet size of less than 30 nm after mixing with the acid. The introduction of negatively charged polar compounds resulted in a 177 % increase in adsorption and an 81 % improvement in static retardation effect. Dynamic adsorption tests indicate that the pseudo-second-order model more accurately describes the kinetics of dynamic adsorption of microemulsions on rock surfaces. Under a fixed flow rate, the dynamic retardation rate increased with the concentration of the microemulsion. In practical acidification, the adsorption of microemulsions results mainly from combined electrostatic forces and fluid scouring, characterized by a continuous process of adsorption and desorption. Scanning electron microscope also confirmed that microemulsions can form an adsorptive film on the rock, reducing the acid-rock reaction rate. This study offers practical guidelines for the selection and application of retardation additives, aiming to enhance the ecological compatibility of chemical treatments in low-permeability limestone reservoirs.

Research on optimization of engineering parameters of effective action distance of multi-stage alternating injection acid etching

This study calibrated the numerical simulation model by using indoor experiments to measure experimental data related to conductivity, acid rock reaction kinetics and acid fluid loss, and combined it with the numerical simulation model to calculate the multi-condition acid flow under multi-physics coupling . The effective action distance of the acid liquid is finally formed, which can be used at 200℃ and 250℃. The effective action distance of the acid liquid is related to the amount of acid liquid and the number of acid liquid injection stages. A set of quick diagrams that can be quickly applied to multi-stage Alternate injection process design and optimized workflow. After calculation, it is concluded that: for the 200℃ formation, it is recommended that the total amount of acid used in the level 3 injection process should be more than 400m3; if level 2 injection is used, taking into account both cost and benefit, the total acid amount of 300m3 can be close to the same amount of acid in level 3 The effective range of the injection. For the 250℃ formation, it is not recommended to use a solution with small liquid volume and multiple stages. If level 3 injection is used, it is recommended that the acid dosage be more than 500m3; if level 2 injection is used, taking into account both benefits and costs, it is recommended to use 400m3 acid liquid . Injection can obtain an effective distance similar to that of level 3 injection with the same amount of acid.

Acid-etched fracture morphology and conductivity of acid fracturing in carbonate rock using novel isolation membrane acid

In recent years, low-viscosity isolation membrane acid (ISM acid) has emerged as a novel retardant acid for matrix acidizing and acid-fracturing in carbonate reservoir. Its ability to create long wormholes in carbonate rock has been extensively studied, while its potential to etch hydraulic fracture and generate conductivity has received less attention. To address the knowledge gap, a series of experiments were conducted in this study, including rheological test, acid-etching simulation experiments, surface laser scanning of acid-fractures, and conductivity tests. The differences in rheological characteristics between ISM acid, blank HCl acid, and gelled acid were compared across different lithology along with the morphology and conductivity of the etched fractures. The viscosity of ISM acid is found to be nearly identical to that of blank HCl, which is 1/26th that of gelled acid. However, the acid-rock reaction rate of ISM acid is only 46–55% compared to blank HCl acid. In dolomite formations, the rate approximates that of gelled acid but is lower in limestone formations, indicating a strong ability for low-viscosity retarding. The heterogeneity of ISM acid etching morphology approaches that of blank HCl acid but exhibits greater retard strength than gelled acid. Under medium to high closure pressure (10–30 MPa), ISM acid generates higher conductivity and better retention ability. This study provides certain guidance for the design of ISM acid fracturing in carbonate reservoir.

Synthesis and Characterization of a Temperature-Sensitive Microcapsule Gelling Agent for High-Temperature Acid Release.

Deep, high-temperature carbonate reservoirs, represented by the Chuanzhong-Gaomo Block and the Penglai Gas Field, have become important supports for increased storage and production in Sichuan Basin. However, acidization in high-temperature to ultrahigh-temperature reservoirs faces several technical challenges, such as fast acid-rock reaction rates, limited acid corrosion distances, and high risks of tubular corrosion. In this study, a novel high-temperature-resistant microencapsulated gelling agent GLE-3 was prepared using N-isopropylacrylamide (NIPAM) as the wall material, acrylamide (AM), 2-acrylamido-2-methylpropanesulfonic acid (AMPS), and N-vinylcaprolactam (NVCL) as the core materials, and N,N'-methylenebis(acrylamide) (MBA) as the cross-linking agent through inverse emulsion polymerization. GLE-3 was structurally characterized using infrared spectroscopy, transmission electron microscopy, and particle size analysis, and its properties were evaluated. The results showed that GLE-3 exhibited uniform particle size distribution ranging from 10 to 100 μm. Under high-temperature conditions of 180 °C and a shear rate of 170 s-1, the viscosity of the gel acid solution remained above 27.8 mPa·s, with a viscosity retention rate of 63.76%. Compared to GLE-1 (uncapsulated), GLE-3 demonstrated improved thermal stability and shear stability after microencapsulation. After 60 min of shearing at 180 °C and shear rate of 170 s-1, the viscosity retention rate was 88.99%. Furthermore, under 180 °C conditions, GLE-3 exhibited good high-temperature slow-release performance compared to GLE-1, which unencapsulated with the same raw materials. By increasing the viscosity of the gel acid, delaying the acid-rock reaction rate, and providing high-temperature slow-release effects, the high-temperature resistance of the acid system was enhanced, ultimately achieving deep acidization in high-temperature reservoirs.

Experimental study of the mechanical properties and microscopic mechanism of carbonate rock subjected to high-temperature acid stimulation

To clarify the effect of acidification on the stress distribution around wells in deep carbonate reservoirs, it is necessary to study the changes in mechanical properties of carbonate rocks under different acid stimulation conditions. In this paper, a novel acid stimulation experiment is designed to investigate the mechanical properties of the carbonate rock through a self-built acid-rock reaction experimental system and triaxial rock mechanics apparatus. The changes in the core mechanical parameters with the acid stimulation time at different acid stimulation temperatures are obtained. Based on stress relaxation, the rheological properties of the core after acid stimulation are explored. The internal structural damage mechanism of the core after high-temperature acid stimulation is as analysed via by SEM. This research finds that the elastic modulus and compressive strength of the core exponentially decrease with increasing of acid stimulation time. The higher the acid stimulation temperature, the faster the core damage rate changes, and the earlier the damage amount tends to stabilize. The core has an obvious rheological mechanical property after acid stimulation. The stress relaxation amplitude exponentially increases with increasing strain during loading. Interestingly, when the acid stimulation temperature reaches 120 °C, a sudden stress drop occurs during stress relaxation. It is also found that the stress relaxation amplitude increases exponentially with increasing acid stimulation time under the same strain level. Moreover, a higher acid stimulation temperature results in greater stress relaxation under a constant acid stimulation time and strain. In addition, the core skeleton is destroyed through acid stimulation, and many complex damaged structures appear inside the core, which leads to a decrease in the core strength, which is the reason for the enhanced rheological characteristics of the rock after acid stimulation. These results can provide insights into the mechanical response mechanism of wellbore acidification.

Study on rock strength weakening in multi-stage acid fracturing using continuous strength test

Multi-stage acid fracturing can boost productivity in low-permeability limestone reservoirs, with success hinging on differential etching and the strength of undissolved regions to keep fractures open. Traditional rock strength test methods have strong randomness and error. This study explores the influence of four acid systems (hydrochloric acid, single-phase retarded acid, gelled acid, and emulsified acid) on fracture surface strength based on a new continuous strength test method. The rock strength weakening variation under different acid types and injection conditions was quantified, and the mechanism of single-phase retarded acid slowing down rock strength reduction was revealed. The results indicated that the fracture surfaces were reduced to a lesser extent than in traditional rock mechanical failure studies. Hydrochloric acid caused up to 28% of rock strength depletion, followed by 23% for gelled acid, 18% for emulsified acid, and 11.8% for single-phase retarded acid. Adjusting the acid injection parameters revealed that longitudinal leak-off at the fracture surface changes the rock's strength failure tendency. The microscopic results confirmed that the appropriate acid-rock reaction rate and viscosity are beneficial in reducing strength by forming the dominant wormhole that “siphons” the subsequent acid more profoundly into the formation, thereby reducing the reaction of the acid with the fracture surface. This study can help to understand better the mechanism by which acid reduces the strength of fracture surfaces and can provide guidance for selecting appropriate acid fluids for acid fracturing in low-permeability limestone reservoirs.

Fracture conductivity and rock appearance in volcanic reservoirs treated by various stimulation techniques

Volcanic reservoirs have complex mineral compositions and highly heterogeneous physical and mechanical properties, making their stimulation quite problematic. This study aimed at clarifying acid-rock reaction and stimulation mechanisms in volcanic reservoirs using 3D scanners and conductivity testing devices. Tests on rock sample conductivity and appearance under such mainstream stimulation technologies as hydraulic fracturing, acid fracturing, and proppant-carrying acid fracturing (PCAF) were performed. The effects of proppant particle size, proppant concentration, acid volume and type, proppant-carrying acid type, and proppant-carrying acid concentration on conductivity and rock sample appearance were analyzed. The appearance of rock samples included dot-, pit-, and strip-like embeddings, as well as acid-etching pits and channels. Larger particle sizes and higher proppant concentrations produced wider propped fractures and higher flow conductivity. Due to complex mineral distribution, acid fracturing failed to produce long etched channels, and the obtained conductivity was low, with a maximum of 8 D·cm at a 5 MPa closure stress. Hydraulic fracturing and PCAF reached a maximum flow conductivity of 155 D·cm at a 5 MPa closure stress, indicating their applicability to volcanic reservoir stimulation. This work helps reveal the acid-rock reaction and stimulation mechanisms of volcanic reservoirs and provides a theoretical basis for their development.

Numerical characterization of acid fracture wall etching morphology and experimental investigation on sensitivity factors in carbonate reservoirs

Carbonate reservoirs are marked by their low porosity and permeability, naturally occurring fractures that develop in a stochastic fashion and exhibit significant heterogeneity. Deep acidification techniques are essential for the efficient development of such oil and gas reservoirs. The effective distance of acid etching (acid etch fracture length) and the fracture conductivity stand as the two most critical parameters for assessing the efficacy of acidizing. The primary objective of using this technique is to extend the effective distance of the acid etch and enhance the fracture conductivity. The "relay-style" full-length acid etched fracture testing method is employed, achieving an accurate match between the testing temperature, pressure, fracture length, and the actual acid fracturing conditions. It employs a large-scale rock plate acid etching experimental device, in conjunction with 3D laser scanning technology, and utilizes orthogonal experimental design methods to conduct detailed numerical characterization of the rock plate fracture surfaces before and after etching with various acid fluid types, acid injection amounts, and acid injection rates. It quantifies the change in the concentration of the residual acid fluid after the acid-rock reaction, calculating the etching volume of the acid fluid and the length of the acidizing fracture. The experimental results demonstrate that both the gelled acid and the clean diverting acid exhibit long acidification distances and strong inhomogeneous etching capabilities. The etch morphology of the clean diverting acid is dominated by pitting-type and stripe-like dissociation, exhibiting a wavy pattern. In contrast, the etch morphology of the gelled acid appears band-like and groove-like. As the acid injection amount increases, the etch length increases. Under on-site working conditions, etch lengths of 46.42 m and 41.63 m were recorded for 20% gelled acid and clean diverting acid, respectively, after 60 min acid injection time. The factors affecting the etch length sensitivity are in the following order: acid injection rate > acid type > etching time. The optimal acid fracturing parameters to achieve the maximum etch length are: The etch is performed at a pump rate of 600 mL/min for 90 min using gelled acid. Quantitative characterization of acid etch fracture morphology can optimize designing parameters of acid fracturing techniques, enhance the efficiency of their modification, and further enhance the development benefits of oil and gas carbonate rock reservoirs.

Effect of the surface-area-to-volume ratio on dissolution and deterioration of acid-corroded sandstone

This study investigates the impact of hydro-chemical action on the deterioration of physical and mechanical properties of rock, with a specific focus on sandstone subjected to HCl, and H2SO4 solutions with pH values of 2 and 5. The research explores the role of the surface-area-to-volume (SATV) ratios of 0.65 and 0.70 in influencing the dissolution and deterioration of sandstone. A chemical kinetic model is developed to explore the diffusion-dissolution mechanism. Following acid corrosion, the porosity of sandstone increases, marked by a decline in small pores (r ≤ 1 μm) and an increase in medium (1 μm < r < 10 μm) and large pores (r ≥ 10 μm). Furthermore, uniaxial compression tests reveal a reduction in peak strength and elastic modulus, an increase in peak strain, diminished brittleness, and enhanced ductility. The study underscores the substantial influence of the SATV ratio, particularly in the case of low pH values in HCl solutions. Following 150 days of corrosion by pH = 2 HCl solution under a SATV ratio of 0.70, the peak stress and elastic modulus decreased by 52.845% and 92.712%, and peak strain increased by 386.186%. The acid-rock reaction is characterized by diffusion and dissolution, with parameters exhibiting a negative correlation with the SATV ratio and a positive correlation with the pH value of solutions. The diffusion is more affected by the SATV ratio rather than the dissolution. The insights derived from this research have implications for the theoretical foundation of safety assessments and disaster prevention in practical engineering scenarios under acidic environments.

Improving oil and gas flowability in tight carbonates with a novel solid delayed acid

The economic development of tight carbonate reservoirs requires hydraulic or acid fracturing stimulation. Acid fracturing better activates natural fractures, resulting in increased stimulated reservoir volume and improving oil and gas flowability. In order to solve the problem of excessive acid-rock reaction due to high temperature, this paper screened four kinds of solid forms of acid with the maximum quantity of acid and reaction rate as the index and formed a high temperature-resistant mixed solid acid system with solid organic acid as the main part and inorganic solid acid as the auxiliary part. The maximum quantity of acid produced and effective acid concentration of the system were greater than 50%, and no residue was precipitated after the complete reaction. Dynamic acid-rock rate tests were performed on different types of retarded acid at 140 °C. The test results show that the solid acid dissolves to form a low-viscosity acid solution, and the reaction rate is one order of magnitude lower than that of gelled and cross-linked acids at the same hydrogen ion concentration, and it is little affected by temperature. Moreover, the paper compares the treatment effect of micro-proppants and solid acids on micro-fractures. The results show that the core permeability improvement multiples up to 900 times under low dissolution of solid acid and the formation of oil and gas flow channels with the same scale as micro-proppants. The experimental results demonstrated the ability of solid delayed acid to transport the fracture leading edge at high temperatures and effectively activate micro-fractures.

A numerical investigation into the propagation of acid-etched wormholes in geothermal wells

Carbonate geothermal reservoirs are widespread in the Beijing-Tianjin-Hebei region, and acidification stands out as the most effective method to enhance the heat recovery potential of these reservoirs. To understand the propagation patterns of acidized wormholes in geothermal reservoirs, a pore-Darcy scale mathematical model of acidizing reactions in geothermal reservoirs has been established. A normal random distribution function is introduced to depict the reservoir's heterogeneity. Using the finite element method, the study simulated the impact of injection rate, acid concentration, diffusion coefficient, and acid-rock reaction rate on wormhole morphology. The findings indicate that the reaction is uniform in the early stage of acidification, becoming non-uniform in the late stage, ultimately forming distinctive wormhole structures. The acidification radius is more extensive along a particular direction post-acidification. Increasing the acid injection rate, acid concentration, and initial specific surface area proves beneficial in enhancing the acidizing effect. The outcomes of this study hold theoretical and technical significance for optimizing the thermal recovery efficiency of geothermal reservoirs.

Experimental investigation of the impacts of supercritical carbon dioxide on acid-etching fracture morphology and conductivity in tight carbonate reservoir

Carbon dioxide (CO2) as energized fluid has been used for acid-fracturing in tight carbonate reservoir. CO2 is often pumped into the wellbore in liquid phase with acid systems, and transited into supercritical state under the high-temperature formation. While the effect of supercritical CO2 (SC-CO2) on acid-etched fracture morphology and conductivity have rarely been investigated. The acid-etching and conductivity experiments were conducted on the outcrops of the Ma5 sub-member of the Ordo Basin in China. The mixed phase reaction simulation device was developed firstly. These experiments involved the mixing of SC-CO2 with various fluids, including formation water and viscoelastic surfactant (VES) acid, as well as different SC-CO2 concentrations with VES acid. The results show that 100 % SC-CO2 is easy to activate natural fractures without dissolution. After 20%SC-CO2 mixed with formation water, the dissolution ability of the mixed solution and conductivity is only 11.8 % and 1 ∼ 2 % of VES acid respectively. Roughness of the morphology created by the mixture of SC-CO2 with VES acid, exhibits a reduction compared to VES acid-etching, accompanied by the presence of wormholes. Additionally, there is a decrease in conductivity and increase in its retention rate. With the increase of SC-CO2 concentration, the roughness of acid-etching fracture decrease and the injection pressure curve becomes more stable. While the reaction rate is also retarded nearly linearly as the SC-CO2 concentration increases. Especially, when the SC-CO2 concentration is up to 40 %, the acid-rock reaction rate reaches only 55 % of that of VES acid. The conductivity of mixed-acid-etched fracture exhibits a segmented characteristic. During the low-medium closure pressure stage, the acid-etched fracture by VES acid generates high conductivity, specifically when it is below 34.5 MPa. While the higher the SC-CO2 concentration in the mixed acid is, the greater the conductivity and retention rate are at pressures above 34.5 MPa during high closure pressure stage. The conductivity of SC-CO2 acid-fracturing fracture depends on the non-uniform etching of the acid solution. The increase in SC-CO2 concentration of the mixed acid not only enhances conductivity and retention rate under high closure pressure, but also reduces the acid volume required for acid-fracturing.