The viscosity of the acid fracturing fluid determines the hydraulic fracturing breakdown pressure required for fracture initiation and governs fracture propagation in rocks. Accurate measurement and control of fluid viscosity are critical for optimizing fracture geometry, supporting curved fracture development, and ensuring uniform acid distribution along the fracture faces. Selecting the appropriate viscosity prevents excessive fluid leak-off into the formation and enhances acid etching for fracture enhancement, ultimately affecting the degree of enlargement of fractures by acid and enabling more effective oil reservoir drainage area optimization.
Primary Purpose of Acid Fracturing Fluid
Acid fracturing fluid treatments are essential in reservoir stimulation of shale formations marked by low porosity and low permeability. The primary aim is to overcome natural seepage barriers and enhance hydrocarbon recovery by creating conductive pathways within tight rock matrices. Acid fracturing achieves this through a dual mechanism: forming fractures by pressurized acid injection, and subsequently enlarging and etching these fractures via controlled acid-rock reactions. This expands the oil reservoir drainage area and improves the productivity of zones previously hindered by formation damage or insufficient permeability.
A further challenge is tailoring the acid fracturing fluid formulation to match the lithology and mechanics of the target reservoir. The acid-rock reaction mechanism and acid-rock reaction rate vary significantly with mineralogy, pressure, temperature, and the use of hydraulic fracturing fluid additives. This impacts not only the rate and style of etching but also the risk of formation blockage, clay swelling, or adverse geochemical interactions, all of which can compromise fracture conductivity and limit long-term production gains.
Shale Oil Reservoir
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Fundamentals of Acid Fracturing in Shale Oil Reservoirs
Mechanisms of Fracture Creation
Fracture creation in tight shale oil reservoirs relies on overcoming high in-situ stresses and rock strength through hydraulic or acid fracturing. In these low permeability environments, large-scale pathways for oil flow rarely exist. The principle involves injecting an acid fracturing fluid at sufficient pressure to exceed the hydraulic fracturing breakdown pressure—the minimum required to initiate cracks in the rock matrix. This process relies directly on fundamental rock mechanics: once the applied pressure surpasses the breakdown threshold, new fractures form, most commonly following the paths of lowest resistance dictated by bedding planes, natural fractures, and mechanical anisotropy within the rock.
Breakdown pressure varies with rock type and fracturing fluid. Studies show fluids like CO₂ create higher breakdown pressures and more intricate fracture networks compared to H₂O or N₂. The mechanics also depend on the formation’s tensile strength, modulus of elasticity, and the presence of weak planes. Critical distance theory—informed by laboratory and field testing—models the necessary fracture initiation pressure as a function of the stress intensity at the crack tip, predicting where and when unstable fracture extension will arise.
Complexity in the created fracture network is further achieved by targeting fracture growth along curved lines rather than straight planes. This approach increases stimulated reservoir volume. Techniques such as cyclic pressure shock fracturing induce pressure pulses, causing repeated initiation and coalescence of fractures which branch and curve, efficiently navigating lithological barriers and lamination heterogeneity. Complex, multi-branched fractures formed this way maximize drainage area and improve access to previously isolated hydrocarbons.
Fracture creation also depends on integrating geological conditions and operational controls. Geological factors—such as stress regime, stratification, mineralogy, and the presence of weak seams—govern the paths fractures can take. Engineering adjustments, including acid fracturing fluid formulation and dynamic pressure management, enable design of networks that best match the natural properties of the reservoir.
Reservoir Characteristics Affecting Acid Fracturing
Low permeability and low porosity are defining traits of shale oil reservoirs. Both properties limit natural fluid flow, making efficient fracture propagation critical for production. In ultratight matrix systems, induced fractures must be sufficiently extensive to connect with existing pore networks or microfractures. However, enlargement of fractures by acid is often uneven due to heterogeneity in rock composition, mineralogy, and texture.
Porosity and permeability control fluid leak-off and acid transport. In rocks with poor pore structure or limited interconnected microfractures, acid leak-off is restricted, making acid etching in hydraulic fracturing less effective. Where natural seepage channels are absent or highly tortuous, techniques to improve channel connectivity become essential. Poor natural seepage channel solutions may include repeated fracturing cycles, use of diverters, or hybrid treatment sequences.
Rock heterogeneity—differing layers, fracture densities, and mineral distributions—creates preferential paths for both fracture propagation and leak-off. Acid-rock reaction mechanism and acid-rock reaction rate vary throughout the reservoir, especially near interfaces between contrasting rock types. Where acid encounters carbonate-rich streaks, rapid reaction can create uneven fracture widths and branched fracture patterns. This can alternatively promote or impede connectivity depending on spatial heterogeneity.
Fluid leak-off is another challenge in heterogeneously fractured shales. High leak-off in zones of increased porosity or open fractures can limit the effective extension of main induced fractures. Conversely, low leak-off zones may hinder acid penetration and subsequent enlargement of the fracture network. The formulation of acid fracturing fluids—including use of gelled or crosslinked acids, and fluid additives tailored to rock type—directly affects these outcomes, enabling operators to enhance low porosity rock permeability and optimize oil reservoir drainage area.
Effective stimulation in these complex environments requires a dual focus: precise control of fracture mechanics and targeted enhancement of rock transport properties through informed hydraulic fracturing fluid formulation and operation. Acid etching for fracture enhancement, managed leak-off, and fracturing along curved trajectories are integral to overcoming the innate barriers posed by low permeability and poor natural connectivity in shale oil reservoirs.
Acid Fracturing Fluid: Composition, Viscosity, and Performance
Components and Formulation of Acid Fracturing Fluids
Acid fracturing fluid formulation centers on tuning chemical systems to maximize fracture conductivity and oil recovery. The most common acid system used is hydrochloric acid (HCl), typically in concentrations from 5% to 28%, selected based on reservoir lithology and treatment objectives. Other acids include organic acids like acetic or formic acid for softer or temperature-sensitive formations. Blends or staged acid systems can be deployed to exploit different reactivities along the treatment interval.
Essential additives accompany the acid. Corrosion inhibitors, intensifiers, iron control agents, and non-emulsifiers protect tubulars, mitigate precipitation, and suppress emulsion formation. Synthetic polymers are increasingly integrated as thickeners—often partially hydrolyzed polyacrylamide (HPAM) or novel copolymers—to elevate viscosity for better acid placement, proppant suspension, and leak-off control. Surfactants, both anionic (e.g., sodium dodecyl sulfate) and non-ionic (e.g., ethoxylated alcohols), are critical for stabilizing foam systems, enhancing wettability alteration, and lowering surface tension for more effective rock–acid contact.
Leak-off and residue management are vital. Fluid-loss additives such as starch-based or advanced synthetic polymers reduce invasion into the matrix, keeping the acid within fractures. Breakers—oxidative (e.g., persulfate) or enzymatic—are deployed to degrade thickeners after treatment, reducing the risk of residue and subsequent formation damage. However, interactions with produced water or under-temperature breakers may yield secondary mineral precipitation like barite, demanding careful system compatibility checks.
Examples of progressive formulations include:
- Retarded acid systems: using surfactant–polymer gels to slow acid-rock reactions for deeper penetration in tight carbonate layers.
- High-temperature, salt-tolerant polymers (e.g., P3A synthetic copolymers) for stable viscosity and minimum residue in deep wells.
- Green chemistry, incorporating L-ascorbic acid, enabling viscosity retention and antioxidant protection at up to 300°F without environmentally persistent byproducts.
Viscosity Measurement and Importance in Acid Fracturing
Accurate measurement of acid fracturing fluid viscosity requires high-pressure, high-temperature (HPHT) viscometers capable of simulating downhole stress and temperature profiles. Key techniques include:
- Rotational viscometers for base viscosity determination.
- HPHT viscometers for advanced protocols, assessing viscoelastic behavior under cyclic thermal or pressure loads.
The importance of viscosity is multifaceted:
- Etching Patterns and Fracture Enlargement: Lower-viscosity acid leads to more dominant wormholing or pitting etch patterns; higher viscosity encourages broader, more uniform channel development, directly governing fracture conductivity and enlargement potential. Raising thickener concentration, for example, results in more extensive etched area and complex fracture growth, as field and dye-tracing laboratory tests confirm.
- Fracture Accessibility and Distribution: Viscous fluids better control acid placement, encouraging acid entry into secondary natural fractures and maximizing oil reservoir drainage area. Quantitative assessment using conductivity measurements post-etch links higher viscosities to more distributed and persistent conductive fracture networks, correlating with higher production rates.
For example, in carbonate-rich Marcellus shale, using self-generating or cross-linked acid systems—where dynamic viscosity is maintained even at reservoir temperatures—results in at least 20–30% higher fracture complexity and drainage coverage compared to unmodified HCl.
Acid–Rock Reaction in Acid Fracturing
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Acid-Rock Reaction Kinetics and their Relationship to Viscosity
The acid–rock reaction mechanism is strongly influenced by fluid viscosity. Classic acid systems react rapidly with carbonate minerals, focusing dissolution near the wellbore and limiting penetration depth. Retarded acid systems, employing viscoelastic surfactants or polymer–acid emulsions, reduce the diffusion rate of hydrogen ions, slowing the overall acid–rock reaction rate. This enables the acid to penetrate deeper into low-permeability or low-porosity formations before becoming spent, promoting broader etching and longer fractures.
Modulation of reaction rate can be tailored through:
- Adjusting surfactant/polymer ratios to fine-tune acid diffusion.
- Sequential acidizing—alternating retarded and regular acid injections—achieves a balance of near-wellbore and deep formation etching, as shown in sequential injection experiments where alternating acid systems yield graded etching and improved reservoir stimulation.
Synergistic effects arise from combinations:
- Polymers combined with nonionic surfactants create robust thickening and increase thermal and salt resistance, as validated by rheological and sand-carrying property evaluation under simulated reservoir conditions.
- Alkali–surfactant–polymer (ASP) blends, and nanocomposite systems (e.g., graphene oxide–polymer), improve both the rate-controlling viscosity and stability of the acid, while also aiding profile control and residual acid removal—critical for optimizing acid fracturing in heterogeneous natural seepage channels and for enhancing recovery from low-permeability or low-porosity formations.
Glass micro-model and coreflood tests confirm that these tailored formulations increase acid contact time, slow reaction with minerals, improve etched area, and ultimately expand oil reservoir drainage, illustrating the practical relationship between acid fracturing fluid composition, viscosity, acid–rock reaction kinetics, and overall reservoir stimulation efficiency.
Influence of Fracture Geometry on Acid Penetration and Effectiveness
Fracture geometry—specifically length, width (aperture), and spatial distribution—critically determines acid penetration and thus the effectiveness of acid fracturing. Long, wide fractures promote extensive acid distribution, but efficiency can decrease due to acid “breakthrough,” where unspent acid rapidly reaches the fracture tip without fully reacting along the path. Aperture variability, especially channelized or rough-walled fractures formed by nonuniform etching, promotes greater penetration by providing preferential pathways and reducing premature acid loss.
- Aperture variability: Channelized surfaces developed by acid etching maintain conductivity under stress and provide preferential acid transport routes.
- Spatial placement: Fractures close to the wellbore allow more uniform acid distribution, while distant or highly branched fractures benefit from staged acid injection or alternating acid/neutral fluid slugs.
- Multi-stage injection: Alternating acid and spacer fluids can rejuvenate etching along extended fracture faces, leading to deeper penetration and more effective enlarging of natural and induced fractures.
Field and laboratory investigations using micro-CT scanning and numerical modeling demonstrate that geometric complexity and roughness control both acid-rock reaction rates and the ultimate extent of permeability enhancement. Proper acid fracturing design thus optimally matches acid system properties and injection schemes to reservoir-specific fracture geometries, ensuring maximum, durable fracture conductivity and enhanced oil recovery.
Optimization Strategies for Effective Acid Fracturing
Selection of Acid Systems and Additives
Optimizing acid fracturing relies heavily on choosing the right acid systems. Retarded acid systems, such as gelled or emulsified acids, are formulated to slow the acid-rock reaction rate. This enables deeper penetration along the fracture and more uniform acid etching. In contrast, conventional acid systems—typically unmodified hydrochloric acid—react rapidly, often restricting the depth of acid penetration and limiting fracture extension, especially in carbonate and high-temperature shale reservoirs. Recent developments include solid acid systems, tailored for ultrahigh-temperature reservoirs, which further retard reaction rates, reducing corrosion and increasing effectiveness through prolonged acid action and improved rock dissolution.
When comparing retarded versus conventional systems:
- Retarded acids are preferred in formations where rapid acid spending near the wellbore diminishes the reach and uniformity of treatment. These acids have been shown to facilitate better enlargement of fractures by acid and improve post-fracture conductivity and oil drainage area.
- Conventional acids may suffice for shallow treatments or highly permeable zones where rapid reaction and minimal penetration are acceptable.
The selection of viscosity modifiers—such as viscoelastic surfactants (VCA systems) or polymer-based gelling agents—depends on reservoir-specific factors:
- Reservoir temperature and mineralogy dictate the chemical stability and performance of viscosity modifiers.
- For high-temperature applications, thermally stable gel breakers like encapsulated oxidizing agents or acid-etching capsules are necessary to ensure the breakdown of gelled acid and efficient post-treatment cleanup.
- The apparent viscosity profile must be tailored so that the acid fracturing fluid maintains sufficient viscosity during pumping (enhancing fracture width and proppant suspension) yet can be fully degraded by gel breakers for effective flowback.
Proper additive choice minimizes formation damage, ensures effective acid etching for fracture enhancement, and maximizes improvement in low-permeability and low-porosity reservoirs. Recent field applications demonstrate that VCA-based acid fracturing fluid formulations, with carefully matched gel breakers, yield enhanced cleanup, lower fluid loss, and improved reservoir stimulation compared to traditional systems.
Operational Parameters Influencing Acid Stimulation Success
Operational control during acid fracturing drastically impacts outcomes. Core operational parameters include pump rate, injected acid volume, and pressure profile management:
- Pump rate: Determines fracture propagation velocity and geometry. A higher rate promotes deeper acid penetration and sustained acid-rock interaction, but must be balanced to avoid premature acid spending or uncontrolled fracture growth.
- Acid injection volume: Influences the length and width of acid-etched fractures. Larger volumes are generally required for low-permeability formations, though optimizing acid volume in tandem with viscosity modifiers can reduce unnecessary chemical use while preserving conductivity.
- Pressure control: Real-time manipulation of bottom-hole and surface pressure ensures the fracture remains open, accommodates fluid loss, and directs acid placement along targeted fracture zones.
In practice, staged or alternating acid injection schedules—where acid types or viscosities are alternated—have been shown to enhance channel formation, promote curved fracture development, and optimize oil reservoir drainage area. For example, two-stage alternating acid injection can create deeper, more conductive channels, outperforming single-stage methods in both laboratory and field settings.
Matching acidizing techniques to reservoir heterogeneity is vital. In shale reservoirs with variable mineralogy and natural fractures, predictive modeling and real-time monitoring are employed to guide the timing and sequence of injections. Adjustments based on fracture attributes (e.g., orientation, connectivity, natural seepage channel improvement) allow operators to fine-tune operational parameters for maximum stimulation and minimal formation damage.
Predictive Modeling and Data Integration
Modern acid fracturing design now integrates predictive models that correlate operational parameters, acid fracturing fluid properties, and post-fracturing conductivity. Advanced models account for:
- Acid-rock reaction mechanism and rate, capturing how acid morphology and etching evolve under field conditions.
- Reservoir-specific factors such as porosity and permeability, mineralogical heterogeneity, and pre-existing fracture networks.
These models leverage empirical data, laboratory results, and machine learning to forecast how alterations in viscosity, pump rates, acid concentration, and thermal profiles affect fracture creation techniques in hydraulic fracturing and long-term reservoir drainage area optimization.
Key guidelines in aligning field constraints and operational design include:
- Selecting viscosity and acid formulation based on the anticipated acid-rock reaction kinetics, expected temperature profile, and completion objectives (e.g., maximizing low porosity rock permeability or solving poor natural seepage channel issues).
- Using data-driven approaches to dynamically adjust acid injection schedules, pump rates, and breaker dosages, optimizing both fracture size and post-treatment recovery.
Examples from recent field deployments show these predictive techniques increase post-fracture conductivity and improve oil production forecasts, enabling more effective and reliable acid fracturing strategies across complex shale and carbonate reservoirs.
Expanding Oil Drainage Area and Sustaining Fracture Conductivity
Formation Blockage Removal and Connectivity Enhancement
Acid etching is a primary mechanism in acid fracturing fluid applications for overcoming the challenge of formation blockage, such as condensate accumulation and mineral scaling, in shale reservoirs. When acid—commonly hydrochloric acid (HCl)—is injected, it reacts with reactive minerals like calcite and dolomite. This acid-rock reaction mechanism dissolves mineral deposits, enlarges pore spaces, and connects previously isolated pores, directly improving porosity and permeability in oil reservoirs. The acid-rock reaction rate, as well as the specific acid fracturing fluid formulation used, varies depending on shale mineralogy and blockage composition.
In carbonate-rich shales, higher concentrations of HCl yield more pronounced etching and blockage removal due to a more rapid and efficient acid-rock reaction. Tailoring the acid composition to the specific carbonate and silicate content of the reservoir optimizes the removal process, effectively restoring natural seepage channels and addressing poor natural seepage channel solutions. Surface roughness on existing fracture faces increases as a result of acid dissolution, directly correlating with enhanced fracture conductivity and more durable flow channels for hydrocarbons. This mechanism has been validated by experimental data showing significant improvements in gas production and injectivity index after tailored acid treatments in low-permeability formations.
Sustained fracture conductivity is critical for the long-term productivity of shale oil wells. Over time, induced fractures can lose conductivity due to proppant crushing, diagenesis, embedment, or fines migration. These processes diminish the opened pathways created by hydraulic fracturing breakdown pressure, severely impacting the recovery of hydrocarbons. Mathematical modeling and laboratory studies show that without proper management, proppant degradation can reduce production by up to 80% over 10 years. Factors such as closure pressure, proppant size, and original fracture surface properties play pivotal roles. Choosing the appropriate proppant and actively managing downhole pressures are essential to maintain the enlarged pathways created by acid etching for sustained oil and gas flow.
Enlargement and Maintenance of Fracture Network
Strategically expanding the oil reservoir drainage area relies on the effective design and deployment of controlled acid systems. These are engineered acid fracturing fluid systems containing additives—such as retarders, gelling agents, and surfactants—to regulate acid placement, control the acid-rock reaction rate, and minimize fluid leak-off during treatment. The result is a more targeted etching process that maximizes fracture creation techniques in hydraulic fracturing and supports the propagation of both primary and secondary (curved) fractures.
Controlled acid systems, especially gelled and in situ gel acids, help manage the placement and longevity of acid within fractures. These systems slow the acid-rock interaction, extending the penetration distance and allowing more comprehensive acid etching for fracture enhancement. This approach increases the stimulated rock volume, expands the oil reservoir drainage area, and addresses challenges with poor natural seepage channel solutions in both carbonate and shale settings. Field cases demonstrate that these techniques create wider, more connected fracture networks, driving greater hydrocarbon recovery.
Maintaining permeability improvements under dynamic reservoir stress is another key consideration. Fracture propagation in rocks subjected to high closure stress often leads to fracture width reduction or premature closure, compromising conductivity. To counteract this, several strategies are employed:
- Stress-coupled perforation technology: This method enables controlled initiation and propagation of fractures, optimizing the compromise between stimulation energy input and fracture network expansion. In the Jiyang Depression, for instance, this technology reduced required energy by 37% while improving both connectivity and environmental outcomes.
- Pre-acidizing treatments: Using polyhydrogen acid systems or other pre-acid fracturing fluids can lower fracture breakdown pressures and reduce initial formation blockage, setting the stage for more efficient and durable fracture creation.
- Geomechanical modeling: Integrating real-time stress measurement and reservoir monitoring allows prediction and adjustment of acid treatment parameters, helping sustain fracture conductivity despite evolving in-situ stress conditions.
These methods—combined with optimized hydraulic fracturing fluid additives and acid fracturing fluid formulation—ensure that permeability gains are retained. They help oil operators enlarge and maintain fracture networks, enhancing low porosity rock permeability and supporting long-term resource extraction.
In sum, through a combination of innovative acid etching practices, advanced controlled acid systems, and geomechanically-informed fracturing strategies, modern reservoir stimulation methods now focus on both maximizing immediate hydrocarbon drainage areas and preserving the fracture conductivity needed for ongoing production performance.
Conclusion
Effective measurement and optimization of acid fracturing fluid viscosity are central to maximizing fracture creation, acid etching efficiency, and long-term oil reservoir drainage in shale formations. Best practices are informed by a nuanced understanding of fluid dynamics under reservoir conditions, as well as the integration of laboratory and field data to ensure operational relevance.
FAQs
Q1: What is the importance of acid fracturing fluid viscosity in shale oil reservoirs?
Acid fracturing fluid viscosity is critical for controlling fracture creation and propagation within shale oil reservoirs. High-viscosity fluids, such as crosslinked or gelled acids, produce wider and more branched fractures. This enables better acid placement and prolongs contact between acid and rock, optimizing the acid-rock reaction mechanism and ensuring the etching is both deep and uniform. Optimal fluid viscosity maximizes fracture width and complexity, directly impacting the efficiency of acid etching for fracture enhancement and the overall oil reservoir drainage area optimization. For example, thickened CO₂ fluids have been shown to improve fracture width and maintain post-treatment permeability, while low-viscosity fluids enable longer, narrower fractures with easier propagation but may risk inadequate etching or channeling of acid flow. Selecting the right viscosity in acid fracturing fluid formulation ensures effective breakdown of formation blockage, long-term fracture conductivity, and substantial expansion of the productive drainage area.
Q2: How does breakdown pressure in hydraulic fracturing affect fracture creation?
Breakdown pressure is the minimum force needed to initiate fractures in the rock during hydraulic fracturing. In shale oil reservoirs with low permeability, precise management of breakdown pressure is fundamental. If the applied pressure is too low, fractures may not open, limiting fluid entry. Too high, and the fracturing may become uncontrollable, risking undesirable fracture propagation. Proper control encourages fractures to develop along natural planes and even curved paths, improving reservoir stimulation. Higher breakdown pressure, when adequately managed, produces more complex fracture networks and enhances the connectivity essential for acid to reach and etch a broader area. Techniques such as borehole notching are used to lower breakdown pressure and better control fracture initiation, affecting both fracture geometry and propagation efficiency. This informed control of hydraulic fracturing breakdown pressure is central to advanced fracture creation techniques in unconventional reservoirs.
Q3: Why is acid etching and enlargement beneficial for low permeability and low porosity reservoirs?
Low permeability and low porosity reservoirs present limited natural seepage channels, which restrict oil mobility and production. Acid etching in hydraulic fracturing uses reactive fluids to dissolve portions of the rock matrix along fracture faces, thereby enlarging these flow paths. This reduces formation blockage and provides new channels for fluids to move more freely. Recent reservoir stimulation methods, including composite and pre-acid systems, have achieved enhanced, long-lasting conductivity and improved oil recovery. These methods are particularly valuable for improving low permeability reservoirs and enhancing low porosity rock permeability, as shown in both field and laboratory studies. The result is a substantial increase in well productivity, with the acid-etched and enlarged fractures functioning as enhanced conduits for hydrocarbon flow.
Q4: What role does porosity and permeability of rocks play in acid fracturing success?
Porosity and permeability directly determine fluid movement and acid accessibility in oil reservoirs. Rocks with low porosity and low permeability hinder the spread and effectiveness of acid fracturing fluids, limiting the success of stimulation operations. To address this, acid fracturing fluid formulation is specifically tailored to include reaction control additives and viscosity modifiers. Enhancing porosity through acid-rock reaction increases the available void space for hydrocarbon storage, while boosting permeability allows easier flow through fracture networks. After acid treatment, multiple studies have shown significant increases in both porosity and permeability, especially where natural seepage channels were previously poor. Improving these parameters enables optimized fracture propagation, sustained production rates, and extended reservoir contact area.
Q5: How does the acid-rock reaction influence the efficiency of drainage area expansion?
The acid-rock reaction mechanism governs how rock is dissolved and how fractures are etched and enlarged during acid fracturing. Efficient control of the acid-rock reaction rate is vital: too fast, and the acid is spent near the wellbore, limiting penetration; too slow, and etching may be insufficient. By managing the reaction through fluid viscosity, acid concentration, and additives, targeted etching along fracture faces is achieved, enabling broader and deeper fracture connectivity. Advanced modeling and laboratory research confirm that optimizing the acid-rock reaction leads to channel-like, highly conductive fractures which dramatically expand the oil drainage area. For example, channelized acid-etched fractures have been documented to yield up to five times higher conductivity than non-etched fractures in carbonate formations. Careful adjustment of acid fracturing fluid composition and injection parameters thus directly determines the scale and efficiency of drainage area improvement.
Post time: Nov-10-2025
