Multistage Acid Fracturing Research Articles

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.

Efficience of multistage fracturing in horizontal wells of the Kashiro-Podolsk deposits

The article is devoted to the methods of extracting reserves from complex carbonate reservoirs based on a complex of geological and technical measures. The parameters influencing the technological efficiency and the increase in oil production are analyzed. These include geological and filtration-capacitive heterogeneity, as well as technological parameters. The division of carbonate rocks into petrotypes is considered in order to assess their impact on input technological indicators – water content, oil flow rate. Geological conditions have been studied, as well as geological and technical parameters that have a significant impact on oil production and reservoir flooding during the multistage acid fracturing. The studied relationships allow for a detailed analysis of the success of events and a detailed approach to the selection of candidate wells.

Performance evaluation of microemulsion acid for integrated acid fracturing in Middle Eastern carbonate reservoirs

Considering the characteristics of carbonate reservoirs in the Middle East, a low-viscosity microemulsion acid that can be prepared on site and has an appropriate retardation ability was developed. It was compared with four conventional acid systems (hydrochloric acid, gelled acid, emulsified acid and surfactant acid) through experiments of rotating disk, multistage acid fracturing and core flooding with CT scanning. The micro-etching characteristics and conductivity of fracture surfaces were clarified, and the variation of saturation field during water invasion and flowback of spent acid and the recovery of oil phase relative permeability were quantitatively evaluated. The study shows that the addition of negatively charged agent to the oil core of microemulsion acid can enhance its adsorption capacity on the limestone surface and significantly reduce the H+ mass transfer rate. Moreover, the negatively charged oil core is immiscible with the Ca2 + salt, so that the microemulsion acid can keep an overall structure not be damaged by Ca2 + salt generated during reaction, with adjustable adsorption capacity and stable microemulsion structure. With high vertical permeability along the fracture walls, the microemulsion acid can penetrate into deep fracture wall to form network etching, which helps greatly improve the permeability of reservoirs around the fractures and keep a high conductivity under a high closure pressure. The spent microemulsion acid is miscible with crude oil to form microemulsion. The microemulsion, oil and water are in a nearly miscible state, with basically no water block and low flowback resistance, the flowback of spent acid and the relative permeability of oil are recovered to a high degree.

Application of Acid Fracturing Technology to Improve Water Yield of Deep Carbonate Geothermal Wells

To achieve the “carbon peak” goal, green and low-carbon energy development is the key. The development and utilization of geothermal resources and the development of deep carbonate geothermal wells in China are analyzed. Based on the principle of chemical reaction between hydrochloric acid and the main components of carbonate rock, four rock samples from geothermal wells were dissolved with 15% and 20% hydrochloric acid, respectively. The comparison showed that 15% hydrochloric acid was more economical and effective. The percolation capacity of acid dissolution fractures was tested through percolation capacity experiments, and the optimal amount of acid solution was determined to be 2-8 PV. It was verified that acid dissolution helps improve fracture percolation capacity. Through the on-site testing of acid fracturing technology in the Xiong’an New Area, it has been verified that the on-site implementation of multi-stage acid fracturing has a significant effect on increasing production. Finally, conclusions are drawn. The method of using acid solution dissolution to increase the water yield of deep carbonate geothermal wells is feasible, and the multi-stage acid fracturing technology is suitable for deep wells and can increase the water output of geothermal wells, which has good promotion value.

Study Investigates Ineffectiveness of Acid Fracturing for Tight Reservoir Rock

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209264, “Ineffectiveness of Acid Fracturing for Stimulating a Tight Fractured Reservoir Rock: A Case Study,” by Huda R. Al-Enezi, Kuwait Oil Company, and Iraj Ershaghi, SPE, University of Southern California. The paper has not been peer reviewed. _ The complete paper describes the analysis of actual performance data for acid fracturing in a tight carbonate formation and the ineffectiveness of the process as measured by the performance responses of the producing wells. An included case study relates to a tight formation that is considered a reservoir rather than a source rock. The formation permeability is in the range of 0.1–5 md. Development has been through numerous horizontal wells with limited multistage acid stimulation. Analysis of performance data for more than 30 wells indicates no fracture flow and very limited stimulated production. Background A category of tight conventional reservoir rocks exists that has not been subjected to horizontal drilling and multistage fracturing. The objective of the authors’ study is to analyze the ineffectiveness of treatment response under acid fracturing and explore the potential of implementing multistage fracturing for a tight reservoir rock using experience gained from unconventional resources. The subject reservoir is a tight carbonate of the Middle Cretaceous age with porosity ranges between 15 and 19% and an average thickness of approximately 90 ft. Oil viscosity ranges between 2.06 and 2.54 cp and average oil gravity is 25° API. The reservoir is a depletion-drive type where the main natural energy is provided by gas in solution. Among the initial wells, only six were successful. The field is very complex, based on stratigraphic and structural characteristics. The first horizontal well was drilled during 2015–16 and was subjected to seven-stage acid fracturing. This resulted in a substantial increase of well cumulative production compared with that of vertical wells. The development plan of this field was implemented with horizontal wells with laterals extending approximately 3,000 ft. Each well was subjected to multistage acid fracturing. Examination of performance data indicated that producing wells suffered from rapid pressure depletion after a production period of 3–6 months. Wells cease natural flow and cannot sustain production even after what is considered acid fracturing without the help of artificial lift. Conventional production plots show that typical performance begins with a high initial rate for a short duration followed by a sharp decline before a stabilization period. To improve and recommend a proper hydraulic fracture design, the authors studied the effectiveness of current stimulation to develop alternative improvement procedures. Methodology The effectiveness of acid stimulation was analyzed and evaluated by using historical production for 4 years. To study the initial rates seen on these horizontal wells, a productivity-prediction tool was used to inversely compute the effective formation-permeability responsible or the observed initial production on these wells. Production data were used to inversely calculate the geometrical averaged permeability from initial field-production data assuming that the initial conditions followed a steady-state regime.

Application of multistage acid fracturing technology in deep carbonate thermal reservoirs

As the most common stimulation treatment in carbonate reservoirs, acid fracturing is also frequently used in carbonate geothermal wells, but it has not been applied in deep carbonate thermal reservoirs. The application of a multi-stage acid fracturing technology in Xiong’an deep carbonate thermal reservoir is introduced in this paper. The field application of technology has achieved a good stimulation effect. Multistage acid fracturing technology can effectively communicate the aquifer of carbonate thermal reservoir, improve the length of acid corrosion fracture, increase the conductivity of thermal reservoir and improve the water yield of a geothermal well. The technology is worthy to be popularized.

Acid System and Stimulation Efficiency of Multistage Acid Fracturing in Porous Carbonate Reservoirs

With little to no natural fracture development and the high calcite content in porous carbonate reservoirs, for multistage acid fracturing, different fluids are used to form a viscous fingering in the fracture, thus enhancing the degree of nonuniform etching. However, existing studies on multistage acid fracturing mainly focused on the combination of fracturing fluid and acid, which is less specific for porous carbonate rocks. Here, the rheological properties of five fluids, including guar-based fluid, cross-linked guar, gelled acid, cross-linked acid, and diverting acid, were studied at each temperature condition, and the viscosity relationship between each fluid was clarified. Based on the rheological properties, the differences between the seven liquid combinations on the etched morphology of the fracture walls were studied and analyzed. The conductivity of the seven acid-etched fractures under different closure stress was simulated. The experimental results showed that the viscosity relationships between the fluids at different temperatures were cross-linked guar > cross-linked acid > diverting acid (spent acid) > gelled acid > guar-based liquid > diverting acid (fresh acid). Because cross-linked acid has higher viscosity than gelled acid, it can form more obvious viscous fingering with a variety of liquids, which is more suitable for acid fracturing stimulation of porous carbonate reservoirs. In addition, the combination of cross-linked and diverting acids was screened out. The multistage alternate injection of this fluid combination could form tortuous and complex etching channels, and its acid-etching fracture conductivity was significantly higher than that of other fluid combinations at different closure stress. In this study, we optimized the fluid combination of porous carbonates and clarified the effect and mechanism of nonuniform etching to provide guidance for the fluid combination selection of multistage alternate acid fracturing process for porous carbonate reservoirs.

Multistage Acid-fracturing Increases the Dolomite Production in High Temperature Deep Horizontal Well

The Sinian dolomite reservoirs in Southwest Oil and Gas Field, China, are characterized by HTHP, high stress, low porosity and permeability, large thickness, and presence of natural fractures and holes. Highly deviated well multistage acid fracturing can help expand the contacting area between wellbore and reservoir, thereby increasing the well production. Through experiments, acid fracturing simulations, staging optimization and field applications, some conclusions were obtained. Large-scale physical modelling experiments and numerical simulations show that, given the high horizontal stress difference, presence of natural fractures, can induce a complex fractures networks. The acid systems with different viscosities, such as self-generating acid, gelled acid and diverting acid, are optimized to, in conjunction with highrate injection and temporary diverting, improve the stimulated reservoir volume and conductivity of acid-fractures in the dolomite reservoirs. The combination of mechanical packers and sliding sleeves facilitate the effective isolation of HTHP dolomite reservoir. The positions of the sliding sleeves are designed according to the high-quality reservoir intervals determined by logging interpretation. The lateral of deviated well is 480m-970m long and stimulated by acid fracturing in 3-6 stages. The post-fracturing tracer testing proves the effectiveness of isolation. This technology was applied for 6 wells, with a daily gas production of (21–110) × 104m3/d after acid fracturing. It provides a new method to increase the production of highly deviated wells or horizontal wells in deep carbonate reservoirs.

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.

An Integrated Experimental Method to Investigate Tool-Less Temporary-Plugging Multistage Acid Fracturing of Horizontal Well by Using Self-Degradable Diverters

Summary Tool-less temporary-plugging multistage acid fracturing of horizontal well is a necessary technology to unlock the production potential and enable commercial productivity for tight carbonate reservoirs. However, this technique has not been investigated experimentally yet, and the plugging behavior of diverters within acid-etched fracture is still unclear. In this paper, we propose an integrated method to experimentally study tool-less multistage fracturing with diverters. First, we introduce an innovative 3D printing method to reproduce the roughness of acid-etched fracture surface and design an acid-etched fracture temporary plugging evaluation system to satisfy the requirements of temporary plugging experiments. Then, we conduct a series of plugging experiments to optimize the diverter's formula for creating a tight plugging zone within an acid-etched fracture under different fracture widths. On the basis of the description of the fracture surface, we further analyze the formation process and mechanism of temporary plugging. Finally, we further verify through laboratory experiments using a modified true tri-axial fracturing system the feasibility of using a single type of diverter and combined diverters to achieve tool-less temporary plugging staged fracturing of horizontal well. The experimental results show the following findings: (1) Pure fibers can realize temporary plugging at lower fracture width (≤2 mm). (2) To achieve temporary plugging, the diameter of particulates should not be less than half of the fracture width under the condition of larger fracture width (≥4 mm). (3) The fracture surface morphology affects the formation time of temporary plugging, but does not affect whether temporary plugging is formed or not. (4) Using a steel plate with a smooth fracture surface to conduct optimization experiments will increase the dosage of diverters, thus increasing the operation cost. (5) Pure particulates cannot achieve favorable plugging effect. This study provides an insight into multistage acid fracturing.

Transient prediction of annular pressure between packers in high-pressure low-permeability wells during high-rate, staged acid jobs

For high-pressure low-permeability wells, wellbore temperature drops drastically in high-rate and multistage acid fracturing process. Under the combined action of the swelling of tubing string and the contraction of annular fluid between packers, annular pressure between packers undergoes violent transient change in staged acid jobs, thereby deteriorating loading on the tubing string and packers. Based on the principle of energy conservation and wellbore heat conduction, the transient prediction of two-dimensional (2D) wellbore temperature field under pumping injection condition was established by considering the effects of heat generated by friction and convection heat exchange. Moreover, the effects of wellbore temperature/pressure changes on the annular volume between packers were analyzed. Furthermore, in combination with the transient prediction model of wellbore temperature, PVT state equation of annular fluid, the calculation model of tubing string radial deformation and the transient seepage equation of the formation, the transient prediction model of annular pressure between packers in high-pressure low-permeability wells was established. Finally, by taking a high-pressure low-permeability well as an example, annular pressure between packers was calculated and the forces on the packers and tubing string were analyzed. According to the prediction results, the tubing string, which was regarded to be safe using conventional design method, exhibited an extremely high risk of failure after taking into account the decrease in annular pressure between packers. Therefore, the decrease in annular pressure should be fully considered in the design of tubing string for high-pressure low-permeability wells in multistage acid fracturing process. In combination with sensitivity analysis results, it can be concluded that formation permeability, injection rate and formation pressure all affected the change in annular pressure between packers.

Chemical-Diversion Agents Can Aid Acid Fracturing in Openhole Horizontal Wells

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE-191415-18IHFT-MS, “Experimental Investigation on Tool-Free Multistage Acid-Fracturing of Openhole Horizontal Wells Using Diversion Agents,” by Jianye Mou, SPE, and Shaodan Tao, China University of Petroleum-Beijing; Xuezhi Hui, CNPC; and Lei Wang, Shicheng Zhang, and Xinfang Ma, China University of Petroleum-Beijing and State Key Laboratory of Petroleum Resources and Prospecting, prepared for presentation at the 2018 SPE International Hydraulic Fracturing Technology Conference and Exhibition, Muscat, Oman, 16–18 October. The paper has not been peer reviewed. In openhole horizontal wells in high-temperature, naturally fractured, deep formations, mechanical segmentation between stages for multistage fracturing operations is high-risk, costly, and sometimes ineffective. Acid fracturing using chemical diversion agents as an alternative to mechanical segmentation has been pilot-tested in some fields with satisfactory results, but the technique has not been studied experimentally or numerically extensively before now. This paper presents a newly designed triaxial fracturing system and describes a series of experiments that verified the validity of tool-free chemical diversion for multistage fracturing of openhole horizontal wells. Introduction Traditional staged fracturing technologies include double-pack single-slip multistage fracturing, packer/sliding-sleeve fracturing, and hydraulic-jetting multi-stage fracturing. These technologies use tools to achieve segmentation between stages. The tools are neither effective nor reliable under some circumstances such as multicluster fracturing inside a stage; refracturing of horizontal wells; and in deep, high-temperature, vuggy, naturally fractured formations. Diverted fracturing with chemical diversion agents has become an option. Diversion has been applied in matrix acidizing and, more recently, in fracturing. Diverted fracturing can be used for both far-field and near-wellbore diversion. Far-field diversion shifts the fracture to unstimulated areas to create complex fractures that increase reservoir contact volume. This paper focuses on near-wellbore diversion, which can be accomplished using mechanical and chemical methods. Recently developed chemical diversion materials include ball sealers, particulates of various sizes, and fiber. These diverters need to be degradable or dissolvable in formation fluids over time. Particulate diverters are available in sizes ranging from several millimeters to a micrometer, allowing them to plug orifices of various sizes and to bridge perforations, fractures, and vugs. Degradable fiber is another commonly used diverter. It can bridge the fracture or fill the gap between particulate diverters to form a tight barrier. Combinations of particulate diverter and fiber have been used often. Diverted fracturing has been used in horizontal wells for refracturing, fracturing multiple clusters in one stage, and even for segmentation in openhole horizontal wells. Refracturing targets regions that have adequate reserves for recovery but are underdeveloped because of non-uniform cluster stimulation. Chemical diversion can restimulate these reservoirs.

Multistage hydraulic jet acid fracturing technique for horizontal wells

Acid fracturing in deep carbonate reservoirs is challenged by deep well stimulation with high temperature (>120 °C), high fracture pressure (>2.0 MPa/m), high flow friction, and strong reservoir heterogeneity. To meet these challenges, a new stimulation method, called the hydraulic jet acid fracturing technique, was developed. According to the mechanisms of hydraulic jet acid fracturing, the authors self-design the downhole injector and pipe strings used in multistage hydraulic jet acid fracturing and provide optimization standards for the nozzle number and diameter combination, abrasive perforating parameter, and pumping program. The technique realizes multistage acid fracturing by hydraulic separation and features simple downhole tools, high temperature resistance (160 °C), low cost and risk. In addition, hydraulic acid injection can extend effective acid corrosion distance nearby well and enhance the acidification effect. The optimal jet phasing is 60 degrees with spiral arrangement to lower formation fracture pressure. A relationship chart between optimal flow rate and wellhead pressure is established, which helps to increase flow rate as far as possible under wellhead assembly capacity and to determine nozzle diameter and number. Results from field tests show that this method can work at a maximum depth of 6 400.53 m, with a total acid volume of up to 618 m3. It is effective in creating acid fractures in ultra-deep horizontal wells.