scholarly journals Laboratory Hydraulic Fracturing Tests of Rock Samples with Water, Carbon Dioxide, and Slickwater

2017 ◽  
Vol 63 (3) ◽  
pp. 139-148 ◽  
Author(s):  
S. Stanisławek ◽  
P. Kędzierski ◽  
D. Miedzińska
Keyword(s):  
Carbon Dioxide ◽  
Hydraulic Fracturing ◽  
Good Method ◽  
Complex Stress ◽  
Experimental Methodology ◽  
Breakdown Pressure ◽  
Face Surface ◽  
Rock Samples ◽  
Wellbore Pressure ◽  
Water Test

Abstract Hydraulic fracturing of rocks boosts the production rate by increasing the fracture-face surface area through the use of a pressurized liquid. Complex stress distribution and magnitude are the main factors that hinder the use of information gathered from in situ hydraulic fracturing in other locations. Laboratory tests are a good method for precisely determining the characteristics of these processes. One of the most important parameters is breakdown pressure, defined as the wellbore pressure necessary to induce a hydraulic fracture. Therefore, the main purpose of this investigation is to verify fracture resistance of rock samples fractured with the assistance of the most popular industry fluids. The experiments were carried out using a stand designed specifically for laboratory hydraulic fracturing. Repeatable results with a relative error within the range of 6-11% prove that the experimental methodology was correct. Moreover, the obtained results show that fracturing pressure depends significantly on fluid type. In the case of a water test, the fracturing pressure was 7.1±0.4MPa. A similar result was achieved for slickwater, 7.5±0.7MPa; however, a much lower value (4.7±0.5MPa) was registered in the case of carbon dioxide.

A Data-Driven Approach to Predict the Breakdown Pressure of the Tight and Unconventional Formation

2021 ◽  
Author(s):  
Zeeshan Tariq ◽  
Murtada Saleh Aljawad ◽  
Mobeen Murtaza ◽  
Mohamed Mahmoud ◽  
Dhafer Al-Shehri ◽  
...  
Keyword(s):  
Neural Network ◽  
Hydraulic Fracturing ◽  
Rock Properties ◽  
Breakdown Pressure ◽  
Rock Samples ◽  
In Situ Stresses ◽  
Fracturing Fluids ◽  
The Neural Network ◽  
Different Types

Abstract Unconventional reservoirs are characterized by their extremely low permeabilities surrounded by huge in-situ stresses. Hydraulic fracturing is a most commonly used stimulation technique to produce from such reservoirs. Due to high in situ stresses, breakdown pressure of the rock can be too difficult to achieve despite of reaching maximum pumping capacity. In this study, a new model is proposed to predict the breakdown pressures of the rock. An extensive experimental study was carried out on different cylindrical specimens and the hydraulic fracturing stimulation was performed with different fracturing fluids. Stimulation was carried out to record the rock breakdown pressure. Different types of fracturing fluids such as slick water, linear gel, cross-linked gels, guar gum, and heavy oil were tested. The experiments were carried out on different types of rock samples such as shales, sandstone, and tight carbonates. An extensive rock mechanical study was conducted to measure the elastic and failure parameters of the rock samples tested. An artificial neural network was used to correlate the breakdown pressure of the rock as a function of fracturing fluids, experimental conditions, and rock properties. Fracturing fluid properties included injection rate and fluid viscosity. Rock properties included were tensile strength, unconfined compressive strength, Young's Modulus, Poisson's ratio, porosity, permeability, and bulk density. In the process of data training, we analyzed and optimized the parameters of the neural network, including activation function, number of hidden layers, number of neurons in each layer, training times, data set division, and obtained the optimal model suitable for prediction of breakdown pressure. With the optimal setting of the neural network, we were successfully able to predict the breakdown pressure of the unconventional formation with an accuracy of 95%. The proposed method can greatly reduce the prediction cost of rock breakdown pressure before the fracturing operation of new wells and provides an optional method for the evaluation of tight oil reservoirs.

Experimental Investigation on Enhanced-Oil-Recovery Mechanisms of Using Supercritical Carbon Dioxide as Prefracturing Energized Fluid in Tight Oil Reservoir

SPE Journal ◽  
2021 ◽  
pp. 1-16
Author(s):  
Lei Li ◽  
Zheng Chen ◽  
Yu-Liang Su ◽  
Li-Yao Fan ◽  
Mei-Rong Tang ◽  
...  
Keyword(s):  
Carbon Dioxide ◽  
Water Resources ◽  
Supercritical Carbon Dioxide ◽  
Hydraulic Fracturing ◽  
Clay Minerals ◽  
Oil Production ◽  
Tight Oil ◽  
Injection Mode ◽  
Oil Development ◽  
Live Oil

Summary Fracturing is the necessary means of tight oil development, and the most common fracturing fluid is slickwater. However, the Loess Plateau of the Ordos Basin in China is seriously short of water resources. Therefore, the tight oil development in this area by hydraulic fracturing is extremely costly and environmentally unfriendly. In this paper, a new method using supercritical carbon dioxide (CO2) (ScCO2) as the prefracturing energized fluid is applied in hydraulic fracturing. This method can give full play to the dual advantages of ScCO2 characteristics and mixed-water fracturing technology while saving water resources at the same time. On the other hand, this method can reduce reservoir damage, change rock microstructure, and significantly increase oil production, which is a development method with broad application potential. In this work, the main mechanism, the system-energy enhancement, and flowback efficiency of ScCO2 as the prefracturing energized fluid were investigated. First, the microscopic mechanism of ScCO2 was studied, and the effects of ScCO2 on pores and rock minerals were analyzed by nuclear-magnetic-resonance (NMR) test, X-ray-diffraction (XRD) analysis, and scanning-electron-microscope (SEM) experiments. Second, the high-pressurechamber-reaction experiment was conducted to study the interaction mechanism between ScCO2 and live oil under formation conditions, and quantitively describe the change of high-pressure physical properties of live oil after ScCO2 injection. Then, the numerical-simulation method was applied to analyze the distribution and existence state of ScCO2, as well as the changes of live-oil density, viscosity, and composition in different stages during the full-cycle fracturing process. Finally, four injection modes of ScCO2-injection core-laboratory experiments were designed to compare the performance of ScCO2 and slickwater in terms of energy enhancement and flowback efficiency, then optimize the optimal CO2-injection mode and the optimal injection amount of CO2slug. The results show that ScCO2 can dissolve calcite and clay minerals (illite and chlorite) to generate pores with sizes in the range of 0.1 to 10 µm, which is the main reason for the porosity and permeability increases. Besides, the generated secondary clay minerals and dispersion of previously cemented rock particles will block the pores. ScCO2 injection increases the saturation pressure, expansion coefficient, volume coefficient, density, and compressibility of crude oil, which are the main mechanisms of energy increase and oil-production enhancement. After analyzing the four different injection-mode tests, the optimal one is to first inject CO2 and then inject slickwater. The CO2 slug has the optimal value, which is 0.5 pore volume (PV) in this paper. In this paper, the main mechanisms of using ScCO2 as the prefracturing energized fluid are illuminated. Experimental studies have proved the pressure increase, production enhancement, and flowback potential of CO2 prefracturing. The application of this method is of great significance to the protection of water resources and the improvement of the fracturing effect.

The Prediction of Wellhead Pressure of Hydraulic Fracturing

2013 ◽  
Vol 405-408 ◽  
pp. 3323-3327
Author(s):  
Feng Shen ◽  
Zhou Wu ◽  
Nan Wang ◽  
Yong Ming Li
Keyword(s):  
Hydraulic Fracturing ◽  
Influencing Factor ◽  
Case Analysis ◽  
Fluid Density ◽  
Interaction Theory ◽  
Breakdown Pressure ◽  
Two Phase ◽  
Wellhead Pressure ◽  
Computing Method ◽  
Calculation Software

The accurate prediction of wellhead pressure in process of hydraulic fracturing is a keypoint to guide the design and construction of the fracturing, and does help in choosing appropriate wellhead equipment and pipeline. This paper calculates the formation breakdown pressure by using a self-made formation stress calculation software, analyzes perforation friction and near-wellbore friction on the basis of Michael theory, eatablishes a model of wellbore friction through Darcy-Weisbach equation and the momentum interaction theory of two-phase flow, and according to the composition of wellhead pressure, makes calculation software which can also analyze the influencing factor of wellbore friction, such as delivery rate, pipe diameter, fracturing fluid density and proppant size. Finally, case analysis verifies the accuracy of the computing method.

Effect of Common Impurities on the Phase Behavior of Carbon-Dioxide-Rich Systems: Minimizing the Risk of Hydrate Formation and Two-Phase Flow

SPE Journal ◽  
2011 ◽  
Vol 16 (04) ◽  
pp. 921-930 ◽  
Author(s):  
Antonin Chapoy ◽  
Rod Burgass ◽  
Bahman Tohidi ◽  
J. Michael Austell ◽  
Charles Eickhoff
Keyword(s):  
Experimental Data ◽  
Carbon Dioxide ◽  
Phase Behavior ◽  
Water Content ◽  
Thermodynamic Model ◽  
Two Phase Flow ◽  
Hydrate Formation ◽  
Experimental Methodology ◽  
Phase Flow ◽  
Two Phase

Summary Carbon dioxide (CO2) produced by carbon-capture processes is generally not pure and can contain impurities such as N2, H2, CO, H2 S, and water. The presence of these impurities could lead to challenging flow-assurance issues. The presence of water may result in ice or gas-hydrate formation and cause blockage. Reducing the water content is commonly required to reduce the potential for corrosion, but, for an offshore pipeline system, it is also used as a means of preventing gas-hydrate problems; however, there is little information on the dehydration requirements. Furthermore, the gaseous CO2-rich stream is generally compressed to be transported as liquid or dense-phase in order to avoid two-phase flow and increase in the density of the system. The presence of impurities will also change the system's bubblepoint pressure, hence affecting the compression requirement. The aim of this study is to evaluate the risk of hydrate formation in a CO2-rich stream and to study the phase behavior of CO2 in the presence of common impurities. An experimental methodology was developed for measuring water content in a CO2-rich phase in equilibrium with hydrates. The water content in equilibrium with hydrates at simulated pipeline conditions (e.g., 4°C and up to 190 bar) as well as after simulated choke conditions (e.g., at -2°C and approximately 50 bar) was measured for pure CO2 and a mixture of 2 mol% H2 and 98 mol% CO2. Bubblepoint measurements were also taken for this binary mixture for temperatures ranging from -20 to 25°C. A thermodynamic approach was employed to model the phase equilibria. The experimental data available in the literature on gas solubility in water in binary systems were used in tuning the binary interaction parameters (BIPs). The thermodynamic model was used to predict the phase behavior and the hydrate-dissociation conditions of various CO2-rich streams in the presence of free water and various levels of dehydration (250 and 500 ppm). The results are in good agreement with the available experimental data. The developed experimental methodology and thermodynamic model could provide the necessary data in determining the required dehydration level for CO2-rich systems, as well as minimum pipeline pressure required to avoid two-phase flow, hydrates, and water condensation.

Coal Mine Hydraulic Fracturing Underground Drainage Research and Engineering Application

2017 ◽  
Vol 863 ◽  
pp. 334-341
Author(s):  
Jun Hui Fu ◽  
Guang Cai Wen ◽  
Fu Jin Lin ◽  
Hai Tao Sun ◽  
Ri Fu Li ◽  
...  
Keyword(s):  
Stress State ◽  
Hydraulic Fracturing ◽  
Coal Mine ◽  
Engineering Application ◽  
Fracture Morphology ◽  
Plane Stress State ◽  
Theoretical Formula ◽  
Test Results ◽  
Breakdown Pressure ◽  
Elastic Mechanics

Using elastic mechanics and fracture mechanics, analyzing the coal seam hydraulic fracturing breakdown pressure, given its theoretical formula. According to hydraulic fracturing stress status, given the form of two typical hydraulic fracture morphology. Analyzing hydraulic fracturing highly elliptical shape. The displacement field in plane stress state is given, and the theoretical formula of fracturing radius of hydraulic fracturing is deduced. The fracturing technology of underground fracturing is presented, and the fracturing location and fracturing parameters are determined. In Sihe Coal Mine conducted fracturing test, the test results showed that: the average of drainage volume of fracturing hole improved 4.4 times compared with non-pressed-hole. The extraction compliance time is reduced by 38%. Roadway tunneling speed was improved by 15%. It can solve the problem of gas overrun in roadway excavation well, and has a good application and popularization value.

Advancements in Step Down Tests to Guide Perforation Cluster Design and Limited Entry Pressure Intensities - Learnings from Field Tests in Multiple Basins

2021 ◽  
Author(s):  
Somnath Mondal ◽  
Min Zhang ◽  
Paul Huckabee ◽  
Gustavo Ugueto ◽  
Raymond Jones ◽  
...  
Keyword(s):  
Pressure Drop ◽  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Field Tests ◽  
Pressure Drops ◽  
Wellbore Pressure ◽  
Hydraulic Fracture Propagation ◽  
Step Down ◽  
Cluster Design

Abstract This paper presents advancements in step-down-test (SDT) interpretation to better design perforation clusters. The methods provided here allow us to better estimate the pressure drop in perforations and near-wellbore tortuosity in hydraulic fracturing treatments. Data is presented from field tests from fracturing stages with different completion architectures across multiple basins including Permian Delaware, Vaca Muerta, Montney, and Utica. The sensitivity of near-wellbore pressure drops and perforation size on stimulation distribution effectiveness in plug-and-perf (PnP) treatments is modeled using a coupled hydraulic fracturing simulator. This advanced analysis of SDT data enables us to improve stimulation distribution effectiveness in multi-cluster or multiple entry completions. This analysis goes much further than the methodology presented in URTeC2019-1141 and additional examples are presented to illustrate its advantages. In a typical SDT, the injection flowrate is reduced in four or five abrupt decrements or "steps", each with a duration long enough for the rate and pressure to stabilize. The pressure-rate response is used to estimate the magnitude of perforation efficiency and near-wellbore tortuosity. In this paper, two SDTs with clean fluids were conducted in each stage - one before and another after proppant slurry was injected. SDTs were conducted in cemented single-point entry (cSPE) sleeves, which present a unique opportunity to measure only near-wellbore tortuosity using bottom-hole pressure gauge at sleeve depth, negligible perforation pressure drops, and less uncertainty in interpretation. SDTs were conducted in PnP stages in multiple unconventional basins. The results from one set of PnP stages with optic fiber distributed sensing were modeled with a hydraulic fracturing simulator that combines wellbore proppant transport, perforation size growth, near-wellbore pressure drop, and hydraulic fracture propagation. Past SDT analysis assumed that the pressure drop due to near-wellbore tortuosity is proportional to the flow rate raised to an exponent, β = 0.5, which typically overestimates perforation friction from SDTs. Theoretical derivations show that β is related to the geometry and flow type in the near-wellbore region. Results show that initial β (before proppant slurry) is typically around 0.5, but the final value of β (after proppant slurry) is approximately 1, likely due to the erosion of near-wellbore tortuosity by the proppant slurry. The new methodology incorporates the increase in β due proppant slurry erosion. Hydraulic fracturing modeling, calibrated with optic fiber data, demonstrates that the stimulation distribution effectiveness must consider the interdependence of proppant segregation in the wellbore, perforation erosion, and near-wellbore tortuosity. An improved methodology is presented to quantify the magnitude of perforation and near-wellbore tortuosity related pressure drops before and after pumping of proppant slurry in typical PnP hydraulic fracture stimulations. The workflow presented here shows how the uncertainties in the magnitude of near-wellbore complexity and perforation size, along with uncertainties in hydraulic fracture propagation parameters, can be incorporated in perforation cluster design.

Determination of the Near-Wellbore Pressure Drop for Dual Casing in Hydraulic Fracturing and Refracturing Applications

2022 ◽  
Author(s):  
Joern Loehken ◽  
Davood Yosefnejad ◽  
Liam McNelis ◽  
Bernd Fricke
Keyword(s):  
Pressure Drop ◽  
Hydraulic Fracturing ◽  
Complex Flow ◽  
Cement Layer ◽  
Natural Rock ◽  
Wellbore Pressure ◽  
Flow Through ◽  
The Difference ◽  
Coefficient Of Discharge

Abstract Due to the increases in completion costs demand for production improvements, fracturing through double casing in upper reservoirs for mature wells and refracturing early stimulated wells to change the completion design, has become more and more popular. One of the most common technologies used to re-stimulate previously fracked wells, is to run a second, smaller casing or tubular inside of the existing and already perforated pipes of the completed well. The new inner and old outer casing are isolated from each other by a cement layer, which prevents any hydraulic communication between the pre-existing and new perforations, as well as between adjacent new perforations. For these smaller inner casing diameters, specially tailored and designed re-fracturing perforation systems are deployed, which can shoot casing entrance holes of very similar size through both casings, nearly independent of the phasing and still capable of creating tunnels reaching beyond the cement layer into the natural rock formation. Although discussing on the API RP-19B section VII test format has recently been initiated and many companies have started to test multiple casing scenarios and charge performance, not much is known about the complex flow through two radially aligned holes in dual casings. In the paper we will look in detail at the parameters which influence the flow, especially the Coefficient of Discharge of such a dual casing setup. We will evaluate how much the near wellbore pressure drop is affected by the hole's sizes in the first and second casing, respectively the difference between them and investigate how the cement layer is influenced by turbulences, which might build up in the annulus. The results will enhance the design and provide a better understanding of fracturing or refracturing through double casings for hydraulic fracturing specialists and both operation and services companies.

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