Acid Fracturing Treatment Research Articles

Study on the Cleanup Mechanism of Microemulsion Acid Based on Microfluidic Experiment

Summary During an acid fracturing treatment, the preflush and spent acid injected by multistage alternate injection will enter the matrix; this part of the aqueous phase entering the matrix will cause serious water blocking damage during crude oil production, hinder the migration of crude oil in the matrix, and reduce the well productivity. There is a large amount of small-sized pore throats in low-permeability bioclastic limestone reservoirs. The small-sized pore throats are important channels for hydrocarbon flow and are more vulnerable to water blocking under the effect of capillary pressure. The multistage alternating injection of microemulsion acid is a key technology to unlock the commercial potential of low-permeability porous limestone reservoirs, which has the advantages of high acid conductivity, long action distance, less solid residue, and low water blocking damage. This technology has demonstrated good usability in field tests, and the relevant laboratory studies mainly focus on understanding the stimulation effect of microemulsion acid through macroscopic core experiments. But there is still no clear explanation at the microscopic level for why this system can expand its invasion range and mitigate the water blocking damage. To evaluate the effect of microemulsion acid in limestone reservoirs and provide a reference for its application, the properties and mechanism of this system are studied in this paper, while the systems commonly used in the acid pressing process (spent acid without cleanup additive, spent acid added with cleanup additive, and spent emulsified acid) are selected as the control group. According to the characteristics of multimode pore throat in limestone reservoir, a special micromodel with CaCO3 coating is developed. The microfluidic research is carried out to visually present the dynamics of multiphase flow during different spent acids invasion and flowback processes. The cleanup mechanism of microemulsion acid was revealed, while highlighting its application advantages through comparative analysis.

A comparative study of fracture conductivity prediction using ensemble methods in the acid fracturing treatment in oil wells

The study of acid fracture conductivity stands as a pivotal aspect of petroleum engineering, offering a well-established technique to amplify production rates in carbonate reservoirs. This research delves into the intricate dynamics influencing the conductivity of acid fractures, particularly under varying closure stresses and in diverse rock formations. The conductivity of acid fractures is intricately interconnected with the dissolution of rock, etching patterns on fracture surfaces, rock strength, and closure stress. To accurately predict fracture conductivity under different closure stresses, a robust model is necessary. This model involves assessing both the baseline fracture conductivity under zero closure stress and the rate of conductivity variation as closure stress fluctuates. Key among the influential factors affecting fracture conductivity is the type of rock within the reservoir. Understanding and predicting the behavior of different formations under disparate closure stresses poses a significant challenge, as does deciphering the diverse effects of treatment parameters such as acid injection rate and strength on fracture conductivity. In this study, the predictive power of XGBoost, a machine learning algorithm, was explored in assessing acid fracture conductivity in dolomite and limestone formations. The findings revealed XGBoost's ability to outperform previous studies in predicting fracture conductivity in both types of formations. Notably, it exhibited superior accuracy in forecasting fracture conductivity under varying treatment conditions, underscoring its robustness and versatility. The research underscores the pivotal role of closure stress, dissolution rate of rock (DREC), and rock strength in influencing fracture conductivity. By integrating these parameters into the design of acid fracturing operations, accurate predictions can be achieved, allowing for the optimization of treatment designs. This study illuminates the potential of XGBoost in optimizing acid fracturing treatments, ultimately bolstering well productivity in carbonate reservoirs. Furthermore, it advocates for the essential nature of separate modeling and analysis based on rock types to comprehend and optimize fracturing processes. The comparison between dolomite and limestone formations unveiled distinct conductivity behaviors, underlining the significance of tailored analyses based on rock type for precise operational optimization.

A New Method for Measuring the Effective Length of Acid-Fracturing Fractures

Acid fracturing as an important stimulation technique, provides strong technical support for the exploration breakthrough and efficient development of carbonate oil and gas reservoirs. Accurately predicting the effective length of acid-fracturing fractures is of great significance for guiding the acid-fracturing design and improving the stimulation effect of acid fracturing. This article fully considers the essential requirement that the long-term conductivity of acid-fracturing fractures is not zero within the effective length segment. Based on the principle of the same acid concentration and acid dissolution amount, the long-term conductivity testing experiment of acid-fracturing fractures under different residual acid concentrations was designed and carried out with the consideration of the common ion effect. The critical acid concentration with long-term conductivity of 0 was obtained. This method overcomes the shortcomings of the existing methods that result in the overestimation of the effective length of acid-fracturing fractures due to inaccurate values of residual acid concentration or short-term conductivity as the determining criterion. The experimental results show that the higher the acid concentration, the deeper the acid etching groove, and the higher the initial conductivity of acid-fracturing fractures. The long-term conductivity decline rate of different acid concentrations is above 80%, which means that using short-term conductivity as an evaluation indicator alone will overestimate the effective length of acid-fracturing fracture and the yield-increasing effect of acid-fracturing treatment. In the case presented in this paper, the critical acid concentration for acid-fracturing fracture with long-term conductivity of 0 is 4%, and the effective length of acid-fracturing fractures is 120 m.

Investigation of Mechanical Properties Evolution and Crack Initiation Mechanisms of Deep Carbonate Rocks Affected by Acid Erosion

Deep tight-gas carbonate reservoirs have huge reserves, with the advantages of having clean and low-carbon characteristics in addition to being a sustainable and stable supply which leads to very high-quality green energy, despite its difficult extraction. The reservoirs are usually modified using acid fracturing before exploitation, but due to acid erosion, the continuous alteration of the mechanical properties of the reservoir rocks complicates the process of predicting the crack initiation pressure. This paper aims to address the difficulties in predicting the crack initiation pressure by conducting a series of acid-etching experiments on carbonate rock samples subjected to splitting and uniaxial compression tests. By examining the variations in the elastic modulus, Poisson’s ratio, tensile strength under distinct acid systems, and acid-etching durations and temperatures, a quantified mathematical model was developed. This model was integrated into a fracture-initiation pressure prediction framework, resulting in a practical and user-friendly tool for the acid fracture-initiation pressure prediction model, which was further demonstrated through field engineering validation. The findings reveal that the elastic modulus, Poisson’s ratio, and tensile strength of carbonate rocks exhibit an inverse relationship with acid-etching time and temperature. Extended acid fracturing durations and high reservoir temperatures are conducive to acid-fracturing transformations. The fracture-initiation pressure-prediction-model analysis disclosed that, compared to the gelled acid, the diverting acid demonstrates a more pronounced reduction in the reservoir fracture pressure under high-temperature and short-duration conditions. An acid system preference diagram was constructed to provide a theoretical foundation for practical engineering applications, delivering valuable insights for optimizing acid fracturing treatments in carbonate reservoirs to provide a boost for the green energy extraction of tight gas.

Technology Focus: Acidizing (June 2023)

The first acid job dates to 1895. Challenges remain, however, when it comes to lithology, coverage, penetration, and management of reaction products. These themes remain a focus for stimulation engineers. In paper SPE 204879, for example, a novel in-situ foam-generation system is introduced that provides effective diversion and leaves no residue. Field applications suggest significantly better performance compared with other diversion systems. In paper SPE 203985, the authors present a 3D acid-fracturing model to calculate fracture geometry induced through multistage alternating injection of pad and acid fluids. Alternating acid with high-viscosity polymer pad promotes nonuniform acid etching and viscous fingering, which leads to longer and narrower channels. Concurrently, investigators are studying methods to achieve effective near-wellbore and far-field bridging using a combination of solids and fiber-laden acid. For those wishing to delve deeper into this subject, paper SPE 206255 makes interesting reading. Completions can play a role in improving acid treatments. Limited entry, as presented in paper SPE 211394, and the so-called “segmented and selective” completions are at the forefront. Paper IPTC 23003 introduces the concept of sweet spots, which are then completed selectively with packers and sliding sleeves. Paper SPE 213406 describes a relatively complex architecture for a trilateral TAML Level 2 well with openhole packers and ball-activated sleeves. Thus, it can be said that most enabling technology is out there. Lastly, engineers have begun to leverage benefits that big data and artificial intelligence potentially offer. Predicting an outcome of an acid job remains hit-and-miss at best—a gap engineers must bridge. In paper SPE 208172, the authors present a predictive model to estimate the efficiency of acid-fracturing treatments in naturally fractured reservoirs using an artificial neural network. They report a predictability error of less than 10%. This may be what we are looking for. I hope you find the selections enlightening. Recommended additional reading at OnePetro: www.onepetro.org. SPE 207514 Subsea Multiwell High-Flow-Rate Riserless Acid Stimulation Campaign With Two-Vessel Approach: A Comparative Case Study by Irma Kusumawati, ConocoPhillips, et al. SPE 205599 A New Method of Carbonate Matrix Stimulation Modeling and Optimization Using Field Experimental Data for Acid Efficiency Calibration and Case Studies in Kazakhstan by Ruslan Kalabayev, SLB, et al. SPE 209673 Reducing Carbon Footprint of Matrix Acidizing in Carbonate Formations: How Much Acid Do We Really Need To Pump? by Mahmoud T. Ali, Baker Hughes

Boosting Reaction Rate of Acids for Better Acid Fracturing Stimulation of Dolomite-Rich Formations

Summary Carbonate reservoirs can be stimulated by injecting acids to boost the rate of hydrocarbon production from low-permeability zones via the creation of conductive pathways. The reaction rate between the acidizing fluid and rock matrix is a key parameter in determining the success of stimulation treatments. Dolomite-rich formations are known to exhibit slower reaction kinetics as compared to calcite. As a result, some acid fracturing treatments fall short of creating an extended fracture or the desirable etching pattern on the fracture faces, thus limiting hydrocarbon flow. Accordingly, the development of an acid package to boost the dolomite dissolution rate will be advantageous to the efficiency of the stimulation treatment in dolomite-rich reservoirs. Accelerating the reaction rate of dolomite with strong mineral acid (i.e., hydrochloric acid, HCl) can be achieved through an additive-driven chemical approach based on the addition of judiciously selected sulfonate-based surfactants. To pinpoint the optimal surfactant(s) type and concentration, static dissolution testing was performed under ambient conditions using outcrop dolomite core samples (Silurian and Guelph). Each core sample was reacted with 28 wt% HCl in the presence and absence of sulfonate-based surfactant additives for a predetermined time. Selected surfactants are used in comprehensive reaction kinetics studies at reservoir conditions using a rotating disk apparatus (RDA). Based on the results of the ambient screening tests, three formulations were found to accelerate the reaction rate by up to 30% as compared to using 28 wt% HCl without the additive(s). The kinetics data collected at a pressure of 3,000 psi and temperatures of 175 up to 300°F showed that the reaction rate of Guelph dolomite can be accelerated by as much as 17–55% with one of the formulations. Coreflood experiments showed an increase in the acid PV to breakthrough (PVBT) when the surfactant package was added to the acid formulation pointing to a rise in the reaction rate of dolomite and the developed acid formulations. The acid formulations showed an improvement in the dolomite and acid reaction rate, which creates the opportunity to apply these formulations in the field to improve the outcome of acid fracturing treatments in dolomite-rich reservoirs.

Experimental Investigations of Acid Fracturing in Layered Carbonate Rocks Utilizing Chelating Agents

One of the methods to improve carbonate formation productivity is acid fracturing. The acid injection creates dissolution along the fracture, which improves fracture conductivity. This study investigated chelating agents such as glutamic diacetic acid and ethylene diamine triacetic acid on acid fracturing treatments to sustain the conductivity of layered minerals of carbonate formations. Chelating agents are less reactive than HCl and do not need large quantities of corrosion inhibitors, especially in high-temperature environments. Three cylindrical samples of 1.5 in. × 6 in. were cored from casted layered calcite and dolomite. The roughness and hardness of the fracture surface before and after the stimulation have been examined. The fracture conductivity was also evaluated before and after acid etching using a core flooding setup at different flow rates under four closure stress values. Inductively coupled plasma analysis has been carried out to estimate rock dissolution based on quantifying calcium and magnesium ions. Results showed that chelating agents have improved fracture conductivity and resulted in a sufficiently rougher fracture surface compared to HCl. The rock samples’ surface hardness has been reduced relatively post-treatment, with chelating agents being gentler on the rock. The novelty of this study is that for the first time, chelating agents have been tested as acid fracturing fluids on carbonate reservoirs for generating sustainable conductivity.

Research and application of acid fracturing stimulation mechanism in ultra-deep subsalt dolomite reservoir in Tarim Basin

Deep and ultra-deep carbonate reservoirs are the focus of exploration and development in future. However, the problems of high pressures in the treatment process, a limited effective etching distance of acid, great acid leak-off, and poor adaptability of the acid system are encountered in this type of oil and gas reservoir. The mechanism of acid fracturing stimulation under different processes and parameters is not clear. Aiming at these issues, the treatment schemes, process optimization, parameter optimization, and liquid system screening are studied in this paper, try to clarify the acid fracturing stimulation mechanism, and the following conclusions are drawn: The acid network fracturing could activate natural fracture to generate a complex fracture network to the greatest extent, and thereby a high output could be achieved; By using of weighted fracturing fluid, the wellhead injection pressure, as well as the performance of equipment required, could be effectively reduced; With 20% gelling acid and 20% retarded acid system, the non-uniform etching could be realized to improve the effective etching distance of acid liquid. The conclusions in this paper shed light on the acid fracturing treatment of deep and ultra-deep carbonate rocks.

Numerical Simulation on Hydrofracture Propagation in Fractured-Vuggy Unconventional Reservoirs

The unconventional reservoirs such as carbonate formation develops complex and diverse storage space structures, and it is composed of large-scale cavity, dissolved vug, and fractures. The carbonate reservoir is highly heterogeneous. Acid fracturing of carbonate reservoir is completed through the complex mechanical mechanism of interaction between vug and hydraulic fracture (HF). We use the equivalent method of reducing the rock strength by acid etching and serious fluid leakoff during interaction of HF and vug to establish a finite element (FE) model of HF propagation during acid fracturing in the fractured-vuggy carbonate reservoir. The model considers the effect of serious fluid leakoff during interaction between HF and vug, mechanism of interaction between HFs and the fracture-vug system, and change in acid etching intensity. Then, we carry out numerical simulation on impacts of injection rate, fluid viscosity, leakoff behavior in fractures and vugs, and natural fracture (NF) approaching angle on HF propagation in acid fracturing and compare the characteristics of injection pressure, fracture pressure, and HF size. It is suggested that the acid fracturing treatment should be operated by increasing the acid solution viscosity to reduce fluid leakoff, injecting fracturing fluid and acid fluid alternatively, increasing injection rate, and injecting fibers and ceramics when small pressure drop occurs during the HF interacts with the fracture-vug. When a large pressure drop occurs, it is suggested that the middle-low viscosity acid be injected at a low rate to etch the carbonate rock and enhance the fracture conductivity. HF propagates under higher pressure when the NF approaching angle is smaller.

Ultra-Deep Dolomite Reservoir Quality Classification and its Effect on Acid-Fracturing Based on Natural Fracture Activity Analysis: A Case Study of the Cambrian Subsalt Reservoir in Northern Uplift of Tarim Basin

Taking the >8,000 m buried Cambrian subsalt dolomite reservoir in the northern uplift of the Tarim Basin as an example, this study used imaging logging, cores, outcrops, and other data to identify natural fractures and obtain parameters of natural fractures, including strike, azimuth, width, length, and apparent porosity, and clarified the characteristics of natural fractures in the well section. Based on the logging data, wellbore rock mechanics, in situ stress, and elastic parameters were established. The analysis of the mechanical characteristics of natural fractures was carried out to find out the shear stress, normal stress, and their ratio of each natural fracture in the reservoir section. Combined with the stress value of each fracture, the quantitative characterization parameter Fractures Geomechanical Activity Index of the mechanical characteristics of natural fractures is established. Combined with the petrophysical parameters of natural fractures, the evaluation model of the quality index of the reservoir containing the natural fractures is established. According to the classification of reservoir quality, combined with the petrophysical properties of the reservoir section, the optimization of the acid-fracturing scheme and injection pressure can be carried out in order to increase the production after acid-fracturing. In this study, the quality of the reservoir with natural fractures is divided into three categories: the QRCF of a Class I reservoir is 0.6∼1, of Class II reservoir is 0.3∼0.6, and of Class III reservoir is less than 0.3. The application of Well L1 and other wells shows that there are great differences in the development of natural fractures at different depths of the Cambrian subsalt dolomite reservoir so as to QRCF. The Class I reservoir is easy for acid-fracturing to achieve high performance. The Class II reservoir needs large-scale acid-fracturing, and the Class III reservoir cannot be acid-fractured under the current methods. The research results provide a reference for the classification of the fracture mechanical activity of an ultra-deep Cambrian subsalt dolomite reservoir and the optimization of acid-fracturing treatment parameters of similar reservoirs.

Pressure Interpretations in Acid Fracturing Treatments

SummaryAcid fracturing is a preferred method of stimulating low-permeability limestone formations throughout the world. The treatment consists of pumping alternating cycles of viscous pad and acid to promote differential etching, thereby creating a conductive acid-etched fracture.Acid type, pad and acid volumes, and the injection rates in the designed pump schedule are based on treatment objectives, rock types, and in-situ conditions such as temperatures, in-situ stress, proximity to water-bearing layers, and others. During the acid fracturing treatment, the acid-rock interaction is often marked by signature pressure responses, that are a combined outcome of acid reaction kinetics, responses to changes in fluid viscosity and densities, fluid-frictional drop in narrow hydraulic fractures, and other such parameters. This paper focuses on interpretation of bottomhole pressures (BHPs) during acid fracturing treatment to separate these individual effects and determine the effectiveness of the treatment.Unlike propped fracturing treatments where most fracturing treatments result in net pressure gain, acid fracturing treatments seldom result in net pressure increase at the end of the treatment because the in-situ stresses are generally relieved during the rock dissolution and fracture width creation process that results from acid-mineral reactions. Not only is the extent of stress relief evident from the difference in the start and the end of the treatment instantaneous shut-in pressures, the loss of stresses is also apparent during the treatment itself, especially in jobs where the treatment data are constantly monitored and evaluated in real time. The study reveals that the changes in pressure responses with the onset of acid in the formation can be successfully used to determine the effectiveness of treatment design and can aid in carrying out informed changes during the treatment. Better understanding of these responses can also lead to more effective treatment designs for future jobs.The interpretation developed in the study can be applied to most of the acid fracturing treatments that are pumped worldwide.

Fatigue acid fracturing: A method to stimulate highly deviated and horizontal wells in limestone formation

As a fundamental technique to stimulate limestone formations, acid fracturing is now facing the problem of high fracture pressure. The fatigue damage in steel is a powerful strategy to reduce strength. And acidizing is the key step of acid fracturing and a useful tool to minimize limestone fracture pressure. Therefore, the combination of acid fracturing and fatigue treatment was investigated in this study. In addition, the interaction between acid fractures and calcite veins and weathering zones is still unclear. And the geometry of acid fractures in highly deviated wells hasn't been investigated in detail. Hence, there are three primary aims of this study: 1. To investigate the specific performance of fatigue acid fracturing in the limestone. 2. To ascertain the interaction between acid fractures and calcite veins and weathering zones. 3. To clarify the acid fractures morphology in highly deviated wells. Based on the tri-axial acid fracturing system, a sequence of conventional acid fracturing and fatigue acid fracturing experiments were carried out in vertical, highly deviated, and horizontal wells. The experimental results demonstrate that fatigue acid fracturing effectively reduced the fracture pressure and weakened stress shadow effect. And the inclination degree is an influencing factor of fracture morphology complexity. The weathering zone and the calcite blocks had a noticeable impact on fracture propagation process. According to the experimental results, the fatigue acid fracturing will generate fresh insight into limestone formation stimulation treatments.

Pumping Schedule Optimization in Acid Fracturing Treatment by Unified Fracture Design

Acid fracturing simulation has been widely used to improve well performance in carbonate reservoirs. In this study, a computational method is presented to optimize acid fracturing treatments. First, fracture geometry parameters are calculated using unified fracture design methods. Then, the controllable design parameters are iterated till the fracture geometry parameters reach their optimal values. The results show higher flow rates are required to achieve optimal fracture geometry parameters with larger acid volumes. Detailed sensitivity analyses are performed on controllable and reservoir parameters. It shows that higher flow rates should be applied for fluids with lower viscosity. Straight acid reaches optimal conditions at higher flow rates and lower volumes. These conditions for retarded acids appear to be only at lower flow rates and higher volumes. The study of the acid concentration for gelled acids shows that both flow rate and volume increase as the concentration increases. For the formation with lower permeability, a higher flow rate is required to achieve the desired larger fracture half-length and smaller fracture width. Further investigations also show that the formation with higher Young’s modulus requires decreasing the acid volume and increasing the optimal flow rate, while the formation with higher closure stress requires increasing the acid volume and decreasing the flow rate.

Key technology of Large Scale Acid Fracturing in Fault-Karst Carbonate Reservoir of S Well with Ultra-Deep Well Depth and Ultra-High Temperature

The target formation of S well is a typical carbonate reservoir, which has ultra-deep depth and ultra-high temperature, with a buried depth of 8 270.0 m, a temperature of 182 ℃, extremely complex engineering and geological conditions and wellbore conditions, leading to great challenges in acid fracturing treatment. It is necessary to carry out targeted optimization research of acid fracturing treatment. Based on the detailed analysis of the three challenges of acid fracturing in this well, the compound acid fracturing treatment of Backfilling well section to centralize treatment + Acid damage to reduce fracture pressure + Combining shallow placement of pipe string and low injection rate of weighted fracturing fluid to increase injection rate+ Pad fluid to open the reservoir and extend the fracture + Alternative injection to create high conductivity fracture + Autogenous acid to dredge the far fault-karst is proposed. A set of acid fracturing fluid system with resistance to ultra-high temperature is optimized through experiments, and different acid fracturing fluid scales are recommended by numerical simulation, and finally the large-scale acid fracturing scheme is optimized. Acid fracturing fluid system with resistance to ultra-high temperature includes polymer fracturing fluid resisting 180 ℃, pressure weighted guar gum fracturing fluid and cross-linked acid resisting 160 ℃, and autogenous acid. The optimal fracturing fluid scale is 1 000~1 200 m3 and the acid fluid scale is 800~1 000 m3. After the large-scale acid fracturing of S well, the test production of natural gas is 10.45×104 m3/d, which makes a breakthrough in the exploration of Shunbei NO.4 fault zone and provides valuable experience for the large-scale acid fracturing of similar reservoirs.

An Artificial Intelligence-Based Model for Performance Prediction of Acid Fracturing in Naturally Fractured Reservoirs.

Acid fracturing is one of the most effective techniques for improving the productivity of naturally fractured carbonate reservoirs. Natural fractures (NFs) significantly affect the design and performance of acid fracturing treatments. However, few models have considered the impact of NFs on acid fracturing treatments. This study presents a simple and computationally efficient model for evaluating acid fracturing efficiency in naturally fractured reservoirs using artificial intelligence-based techniques. In this work, the productivity enhancement due to acid fracturing is determined by considering the complex interactions between natural and hydraulic fractures. Several artificial intelligence (AI) techniques were examined to develop a reliable predictive model. An artificial neural network (ANN), a fuzzy logic (FL) system, and a support vector machine (SVM) were used. The developed model predicts the productivity improvement based on reservoir permeability and geomechanical properties (e.g., Young’s modulus and closure stress), natural fracture properties, and design conditions (i.e., acid injection rate, acid concentration, treatment volume, and acid types). Also, several evaluation indices were used to evaluate the model reliability including the correlation coefficient, average absolute percentage error, and average absolute deviation. The AI model was trained and tested using more than 3100 scenarios for different reservoir and treatment conditions. The developed ANN model can predict the productivity improvement with a 3.13% average absolute error and a 0.98 correlation coefficient, for the testing (unseen) data sets. Moreover, an empirical equation was extracted from the optimized ANN model to provide a direct estimation for productivity improvement based on the reservoir and treatment design parameters. The extracted equation was evaluated using validation data where a 4.54% average absolute error and a 0.99 correlation coefficient were achieved. The obtained results and degree of accuracy show the high reliability of the proposed model. Compared to the conventional simulators, the developed model reduces the time required for predicting the productivity improvement by more than 60-fold; therefore, it can be used on the fly to select the best design scenarios for naturally fractured formations.

Effect of fiber on the rheological properties of gelled acid

Degradable fiber is widely used to assist gelled acid diversion and reduce acid leak-off in the acid stimulation of carbonate hydrocarbon reservoirs in Sichuan Basin of China. The rheological properties of an acid system will affect the geometry of the acid-etching fracture. However, the effect of fiber on the rheological properties of gelled acid is not yet clear. This paper investigates the rheological properties of gelled acid with various fiber concentrations at different temperatures. The results show that when the temperature is less than the degradable temperature of the fiber, the apparent viscosity of gelled acid rises gradually with an increase in fiber concentration, while the fiber has no significant effect on the viscosity of gelled acid at the degradable temperature. The dissolution process of fiber in gelled acid experiences none-dissolution, surface dissolution, dissolution and fining, and a complete dissolution stage from low to high temperatures, which all have different effects on gelled acid viscosity. The fiber links more gelling agent molecules of gelled acid together to form a quasi-network structure between the fiber and fiber and the fiber and polymer, which results in a rise in the viscosity of gelled acid. The acid system also shows a strong shear thinning property under different temperatures and fiber concentrations. However, the power-law index n of this acid system always maintains a steady average value of about 0.181, while the change pattern of consistency index K is similar to the change in viscosity with varying fiber concentrations and temperatures. The research results are useful for acid fracturing treatment design in carbonate reservoir.

Acid Fracturing Optimizing Design and Application in Deep Naturally Fractured Carbonate

More than 30% of carbonate reservoirs in the Tarim oilfield and XiNan oil-gas field are naturally fractured-vuggy reservoirs, of which the production is high in most cases and economic returns can be achieved within a short period of time. Acid fracturing is one of the key technology for development of such naturally fractured-vuggy reservoirs. Mud overflow and loss may be emerged at the same time while drilling fractured-vugular carbonate, once it happened, the well control will become complicated. So, the wellbore is drilled a certain distance up or transversal to these huge caves or natural fractures, and acid fracturing will be executed to connected the reservoirs to obtain the hydrocarbon in the reservoir. Acid-fracturing design of fractured-vugular carbonate is based on the relationship between the wellbore and fractured-vugular reservoirs. The acid fracturing design in naturally fractured-vuggy carbonate reservoir is different from the conventional one, it should be optimized based on the spatial positions of the fracture-vuggy body identified via geophysical prospecting, the wellbore and the distance between the two. In the case that the wellbore precisely reaches the top of the fracture-vuggy body, good oil and gas show or overflow is frequently happened. At this moment, drilling ceases and the wellbore are cemented and completed. The small-scale acid fracturing treatment is then carried out, and connectivity between etched fractures and the top of the fracture-vuggy body will lead to high hydrocarbon production. If a certain distance exists between the wellbore and fracture-vuggy reservoirs, 3D seismic imaging will be adopted to calculate the vertical distance between the center of the storage body and the wellbore, which is then used to optimize the injected fluid volume, pump rate and acid fracturing techniques. To create connectivity with the fracture-vuggy storage body relatively far away from the wellbore, acid fracturing involving preflush or multi-stage injection is used. Pressure drops by several ∼ several tens of MPa usually occur as the artificial fracture propagates into the fracture-vuggy body. After fracturing penetrating into the fracture-vuggy body, acid injection starts. During the early acid injection, the pump rate is raised up for longer etched length inside the fracture. It is then lowered during the late acid injection to improve the conductivity of etched fractures. If multiple fracture-vuggy bodies exist near the wellbore, the temporary diverting acid-fracturing will be treated, optimized with respect to the distance between the wellbore and different fracture-vuggy storage bodies, spatial relationship between the maximum principal stress direction and fracture-vuggy storage body and the trend of natural fractures, will be implemented to communicate with multiple naturally fractured vuggy reservoirs. This acid fracturing integrating geophysical prospecting and wellbore trajectory has been applied in hundreds of wells in the Tarim oilfield. Moreover, the success rate of such acid fracturing treatments is increasing with the advancement in the characterization of the fracture-vuggy reservoirs.

Effect of different types of stimulation fluids on fracture propagation behavior in naturally fractured carbonate rock through CT scan

Acid fracturing of carbonate rock starts with formation breakdown and fracture propagation caused by stimulation fluids. The effectiveness of acid fracturing largely depends on the behavior of fracture propagation. While fracture propagation of fractured carbonate rock is greatly influenced by natural fractures and fluid types. So far, some scholars have studied the influence of nonreactive fracturing fluid on fracture propagation, but the comparison of effect between nonreactive fracturing fluid and reactive fracturing fluid on fracture propagation is rarely noticed. In this paper, true tri-axial experiments on carbonate rock (200 mm × 200 mm × 200 mm) are presented; the experiment made a comparative study on the effect of nonreactive fracturing fluid (water, guar fracturing fluid) and reactive fracturing fluid (self-generated acid, gelled acid, VES acid) on fracture propagation in fractured carbonate rock. Besides, fracture morphology was revealed through CT scan and 3D reconstruction technology. In this way, influence of natural fractures and fluid types on hydraulic fracture propagation during acid fracturing was quantitatively analyzed. Results show that these two factors indeed exert great impact on fracture propagation behavior. As acid is more conducive to connection of natural fractures, hydraulic fractures induced by acid can propagate along natural fractures after initiating from natural fractures, and the process would not be restricted by maximum horizontal stress. As a result, a longitudinal fracture parallel to the wellbore is formed. Compared with self-generated acid and gelled acid, VES acid is more liable to connect natural fractures and form complex fracture network during acid fracturing. No matter reactive or nonreactive fracturing fluid is applied to conduct fracturing experiments, hydraulic fracture propagation in carbonate rock with few natural fractures would be restricted by maximum horizontal stress, and transverse fractures perpendicular to the wellbore would be formed after fracturing. In addition, breakdown pressure of rock samples is also affected by natural fractures and fluid types. To be specific, gelled acid decreases rock's breakdown pressure to the greatest extent when numerous natural fractures exist in the rock; the breakdown pressure caused by gelled acid is only 56.7% of which caused by water. However, the gelled acid has little contribution to decrease the breakdown pressure of the carbonate rock with few natural fractures. In a word, the experiment reveals effect of stimulation fluid types on hydraulic fracture propagation in fractured carbonate rock, which provides some guidance for acid-fracturing treatment in carbonate reservoir.

Acid-etching fracture morphology and conductivity for alternate stages of self-generating acid and gelled acid during acid-fracturing

Initial fracture morphology and variation of acid-rock reaction temperature caused by alternate stages were ignored in the traditional alternate multistage acid-fracturing experiments, so a new design method of experiment simulation was proposed with these considerations in this paper. Alternate multistage acid-fracturing experiments were carried out based on this new method through using self-generating acid and gelled acid, while the influence of alternate stages on acid-etching fracture morphology and conductivity were also investigated. The study shows that acid smoothing the peaks are stronger than deepening the valleys on rough fracture during alternate acid-fracturing and the tortuosity of fracture surface also increased after acidizing. Injection time of self-generating acid at high temperature caused by alternate stages is the main influences on the acid-etching pattern, while that of gelled acid has little effect. Excessive dissolved-rock of one alternate stage is beneficial to creating high initial conductivity, but the retention rate of conductivity is the lowest under medium and high closure stress. Although rough initial fracture has a little contribution to generation high conductivity, two alternate stages with moderate acid-etching creates high conductivity and improves the retention rate of conductivity under medium and high closure stress. It is useful to select reasonable alternate stages for self-generating acid and gelled acid in multistage acid-fracturing treatment.

Case study of acid fracturing of Ordovician geothermal reservoir in Taiyun area

The thermal reservoir in Taiyun area mainly consists of Ordovician and Cambrian carbonate formations. The target interval of example well contains more than 95% carbonate, being thick, argilliferous and have well-developed natural fissures and rich hot water. However, sometimes stimulation is necessary to achieve the designed water production rate. In this paper, multistage alternating injection acid fracturing technology is selected according to lithologic characteristics of geothermal reservoir. A gel acid, which is a composite of 20%HCl+0.8%SHY1+2% corrosion inhibitor+1.5% iron ion stabilizer+1% cleanup additive, is optimized and developed by experimental tests. Its viscosity can reach 27 mPa·s. Then, pumping schedule of multi-stage alternate injection acid fracturing is optimized by numerical simulator of acid fracturing design. It is shown from job pressure of field sample well that resistance reduction ability of gel acid needs to be further improved. Moreover, from the analysis results of pressure decline after acid fracturing, the fluid efficiency is 42.32%, net pressure is 3.3 MPa, and the dynamic fracture length is 107m, the maximum fracture width is 8.6mm by fitting treatment pressure. The water production increase factor reaches 1.2 after acid fracturing treatment. Therefore, the acid fracturing treatment is successful.