Pressure Interpretations in Acid Fracturing Treatments

2021 ◽  
Author(s):  
Vibhas J. Pandey
Keyword(s):  
In Situ Stress ◽  
Hydraulic Fractures ◽  
Fluid Viscosity ◽  
Acid Rock ◽  
Rock Interaction ◽  
Fracture Width ◽  
Acid Fracturing ◽  
In Situ Conditions ◽  
Net Pressure

Abstract Acid 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 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 is 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.

A New Method for Measuring Acid Effective Consumption Time in Acid Fracturing

2014 ◽  
Vol 1004-1005 ◽  
pp. 639-647 ◽  
Author(s):  
Jian Ye Mou ◽  
Ke Xiang Zheng ◽  
Hua Jian Chen ◽  
Han Zhang
Keyword(s):  
Reaction Model ◽  
New Method ◽  
Experimental Result ◽  
Acid Rock ◽  
Acid Fracturing ◽  
In Situ Conditions ◽  
Acid Consumption ◽  
Key Factor ◽  
Flow Reaction

In acid fracturing, the fast acid-rock reaction limits live acid penetration distance. Many kinds of acids were developed to reduce the acid-rock reaction rate. Acid effective consumption time in the fracure is a key factor for accurate prediction of live acid penetraiton distance in acid fracturing designs. In this paper, we developed a new method for measuring acid effective consumption time in the fracture and did experimental result matching to obtain effective acid diffusion coefficient with a acid flow-reaction model. Firstly, we designed a apparatus and corresponding experimental procedure. Then used the new method to measure the effective consumption time for gel acid and crosslinked acid. The new method uses reservoir core samples and is convenient to heat all the fluid as well as pipe lines to the reservoir tempeature, which reflects in-situ conditions more reliably. In the experiment, the rock mass loss with time was measured, based on which the acid consumption time is predicted. Under the experiment conditoins, the gel acid has a effecive consumption time about 17-minute, and the crosslinked acid has about 22-minutes at 130°. Finally, a model of acid flow-reaction in a fracture was used to match experimental results to obtained the acid diffution coeffecient. The results from this study help improve accuracy in acid fracturing designs.

scholarly journals Apparent Toughness Anisotropy Induced by “Roughness” of In-Situ Stress: A Mechanism That Hinders Vertical Growth of Hydraulic Fractures and Its Simplified Modeling

SPE Journal ◽  
2019 ◽  
Vol 24 (05) ◽  
pp. 2148-2162 ◽  
Author(s):  
Pengcheng Fu ◽  
Jixiang Huang ◽  
Randolph R. Settgast ◽  
Joseph P. Morris ◽  
Frederick J. Ryerson
Keyword(s):  
Hydraulic Fracture ◽  
High Stress ◽  
In Situ Stress ◽  
Height Growth ◽  
Hydraulic Fractures ◽  
Simple Relationship ◽  
Vertical Growth ◽  
Stress Profiles ◽  
Fracture Height

Summary The height growth of a hydraulic fracture is known to be affected by many factors that are related to the layered structure of sedimentary rocks. Although these factors are often used to qualitatively explain why hydraulic fractures usually have well–bounded height growth, most of them cannot be directly and quantitatively characterized for a given reservoir to enable a priori prediction of fracture–height growth. In this work, we study the role of the “roughness” of in–situ–stress profiles, in particular alternating low and high stress among rock layers, in determining the tendency of a hydraulic fracture to propagate horizontally vs. vertically. We found that a hydraulic fracture propagates horizontally in low–stress layers ahead of neighboring high–stress layers. Under such a configuration, a fracture–mechanics principle dictates that the net pressure required for horizontal growth of high–stress layers within the current fracture height is significantly lower than that required for additional vertical growth across rock layers. Without explicit consideration of the stress–roughness profile, the system behaves as if the rock is tougher against vertical propagation than it is against horizontal fracture propagation. We developed a simple relationship between the apparent differential rock toughness and characteristics of the stress roughness that induce equivalent overall fracture shapes. This relationship enables existing hydraulic–fracture models to represent the effects of rough in–situ stress on fracture growth without directly representing the fine–resolution rough–stress profiles.

scholarly journals Estimating Unpropped-Fracture Conductivity and Fracture Compliance From Diagnostic Fracture-Injection Tests

SPE Journal ◽  
2018 ◽  
Vol 23 (05) ◽  
pp. 1648-1668 ◽  
Author(s):  
HanYi Wang ◽  
Mukul M. Sharma
Keyword(s):  
Earth Science ◽  
Mathematical Framework ◽  
Field Scale ◽  
Time Data ◽  
Fracture Conductivity ◽  
Reliable Technique ◽  
Fracture Width ◽  
In Situ Conditions ◽  
Fracture Closure

Summary A new method is proposed to estimate the compliance and conductivity of induced unpropped fractures as a function of the effective stress acting on the fracture from diagnostic-fracture-injection-test (DFIT) data. A hydraulic-fracture resistance to displacement and closure is described by its compliance (or stiffness). Fracture compliance is closely related to the elastic, failure, and hydraulic properties of the rock. Quantifying fracture compliance and fracture conductivity under in-situ conditions is crucial in many Earth-science and engineering applications but is very difficult to achieve. Even though laboratory experiments are used often to measure fracture compliance and conductivity, the measurement results are influenced strongly by how the fracture is created, the specific rock sample obtained, and the degree to which it is preserved. As such, the results may not be representative of field-scale fractures. During the past 2 decades, the DFIT has evolved into a commonly used and reliable technique to obtain in-situ stresses, fluid-leakoff parameters, and formation permeability. The pressure-decline response across the entire duration of a DFIT reflects the process of fracture closure and reservoir-flow capacity. As such, it is possible to use these data to quantify changes in fracture conductivity as a function of stress. In this paper, we present a single, coherent mathematical framework to accomplish this. We show how each factor affects the pressure-decline response, and the effects of previously overlooked coupled mechanisms are examined and discussed. Synthetic and field-case studies are presented to illustrate the method. Most importantly, a new specialized plot (normalized system-stiffness plot) is proposed, which not only provides clear evidence of the existence of a residual fracture width as a fracture is closing during a DFIT, but also allows us to estimate fracture-compliance (or stiffness) evolution, and infer unpropped fracture conductivity using only DFIT pressure and time data alone. It is recommended that the normalized system-stiffness plot (NS plot) be used as a standard practice to complement the G-function or square-root-of-time plot and log-log plot because it provides very valuable information on fracture-closure behavior and the properties of fracture-surface roughness at a field-scale, information that cannot be obtained by any other means.

Interpretation of Hydraulic Fracturing Pressure in Tight Gas Formations1

2014 ◽  
Vol 136 (3) ◽  
Author(s):  
Gun-Ho Kim ◽  
John Yilin Wang
Keyword(s):  
Hydraulic Fracturing ◽  
In Situ Stress ◽  
Pressure Effects ◽  
Tight Gas ◽  
New Methods ◽  
Accurate Interpretation ◽  
Fracture Fluid ◽  
Net Pressure ◽  
Property Changes

The interpretation of hydraulic fracturing pressure was initiated by Nolte and Smith in the 1980s. An accurate interpretation of hydraulic fracturing pressures is critical to understand and improve the fracture treatment in tight gas formations. In this paper, accurate calculation of bottomhole treating pressure was achieved by incorporating hydrostatic pressure, fluid friction pressure, fracture fluid property changes along the wellbore, friction due to proppant, perforation friction, tortuosity, casing roughness, rock toughness, and thermal and pore pressure effects on in-situ stress. New methods were then developed for more accurate interpretation of the net pressure and fracture propagation. Our results were validated with field data from tight gas formations.

Roughness of Hydraulic Fractures: Importance of In-Situ Stress and Tip Processes

SPE Journal ◽  
2001 ◽  
Vol 6 (01) ◽  
pp. 4-13 ◽  
Author(s):  
D.B. van Dam ◽  
C.J. de Pater
Keyword(s):  
In Situ Stress ◽  
Hydraulic Fractures

scholarly journals Numerical Simulation on Mesoscale Mechanism of Seepage in Coal Fractures by Fluid-Sloid Coupling Method

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-11
Author(s):  
Kai Si ◽  
Ruidong Peng ◽  
Leilei Zhao ◽  
Yan Zhao ◽  
Yaheng Zhu ◽  
...  
Keyword(s):  
Coupling Effect ◽  
Numerical Models ◽  
Seepage Flow ◽  
In Situ Stress ◽  
Low Velocity ◽  
Fracture Width ◽  
Gas Seepage ◽  
Fluid Seepage ◽  
Flow Flux

Trying to reveal the mechanism of gas seepage in coal is of significance to both safe mining and methane exploitation. A series of FEM numerical models were built up and studied so as to explore the mesoscale mechanism of seepage in coal fractures. The proposed mesoscale FEM model is a cube with micron fractures along three orthogonal directions. The distribution of velocity and pressure under fluid-solid coupling was obtained, and furthermore, the seepage flow flux and an equivalent permeability of the whole model were calculated. The influences of fracture width, outlet velocity, and in situ stress level on seepage were investigated. The numerical results show that nonlinear Darcy seepage occurs during low velocity zone. The permeability is increased linearly with the increasing of facture width and outlet velocity. A certain change of lateral coefficient of in situ stress also affects seepage. The permeability is increased sharply once deviating the isotropic spherical stress state, but it is no longer changed obviously after the lateral coefficient has been increased or decreased more than 20%. The mesoscale seepage mechanism in coal fractures has been preliminarily revealed by considering fluid-solid coupling effect, and the key factors influencing fluid seepage in coal fractures were demonstrated. The proposed methods and results will be helpful to the further study of seepage behaviour in coal with more complex structures.

scholarly journals Numerical Investigation of Injection-Induced Fracture Propagation in Brittle Rocks with Two Injection Wells by a Modified Fluid-Mechanical Coupling Model

Energies ◽  
2020 ◽  
Vol 13 (18) ◽  
pp. 4718
Author(s):  
Song Wang ◽  
Jian Zhou ◽  
Luqing Zhang ◽  
Zhenhua Han
Keyword(s):  
Fracture Propagation ◽  
In Situ Stress ◽  
Hydraulic Fractures ◽  
Fracture Networks ◽  
Breakdown Pressure ◽  
Injection Wells ◽  
Mechanical Coupling ◽  
Stress Shadow ◽  
Well Spacing

Hydraulic fracturing is a key technical means for stimulating tight and low permeability reservoirs to improve the production, which is widely employed in the development of unconventional energy resources, including shale gas, shale oil, gas hydrate, and dry hot rock. Although significant progress has been made in the simulation of fracturing a single well using two-dimensional Particle Flow Code (PFC2D), the understanding of the multi-well hydraulic fracturing characteristics is still limited. Exploring the mechanisms of fluid-driven fracture initiation, propagation and interaction under multi-well fracturing conditions is of great theoretical significance for creating complex fracture networks in the reservoir. In this study, a series of two-well fracturing simulations by a modified fluid-mechanical coupling algorithm were conducted to systematically investigate the effects of injection sequence and well spacing on breakdown pressure, fracture propagation and stress shadow. The results show that both injection sequence and well spacing make little difference on breakdown pressure but have huge impacts on fracture propagation pressure. Especially under hydrostatic pressure conditions, simultaneous injection and small well spacing increase the pore pressure between two injection wells and reduce the effective stress of rock to achieve lower fracture propagation pressure. The injection sequence can change the propagation direction of hydraulic fractures. When the in-situ stress is hydrostatic pressure, simultaneous injection compels the fractures to deflect and tend to propagate horizontally, which promotes the formation of complex fracture networks between two injection wells. When the maximum in-situ stress is in the horizontal direction, asynchronous injection is more conducive to the parallel propagation of multiple hydraulic fractures. Nevertheless, excessively small or large well spacing reduces the number of fracture branches in fracture networks. In addition, the stress shadow effect is found to be sensitive to both injection sequence and well spacing.

Methane adsorption on shale under in situ conditions: Gas-in-place estimation considering in situ stress

Fuel ◽  
2022 ◽  
Vol 308 ◽  
pp. 121991
Author(s):  
Feng Miao ◽  
Di Wu ◽  
Xueying Liu ◽  
Xiaochun Xiao ◽  
Wenbo Zhai ◽  
...  
Keyword(s):  
In Situ Stress ◽  
Methane Adsorption ◽  
In Situ Conditions

Analyzing the Dynamics of Mineral Dissolution during Acid Fracturing by Pore-Scale Modeling of Acid-Rock Interaction

SPE Journal ◽  
2021 ◽  
pp. 1-14
Author(s):  
Jiahui You ◽  
Kyung Jae Lee
Keyword(s):  
Numerical Model ◽  
Multiphase Flow ◽  
Scale Model ◽  
Pore Scale ◽  
Acid Rock ◽  
Rock Interaction ◽  
Acid Fracturing ◽  
Geometry Model ◽  
The Impact ◽  
Pore Scale Model

Summary Hydrochloric acid (HCl) is commonly used in acid fracturing. Given that the interaction between acid and rock affects multiphase flow behaviors, it is important to thoroughly understand the relevant phenomena. The Darcy-Brinkman-Stokes (DBS) method is most effective in describing the matrix-fracture system among the proposed models. This study aims to analyze the impact of acid-rock interaction on multiphase flow behavior by developing a pore-scale numerical model applying the DBS method. The new pore-scale model is developed based on OpenFOAM, an open-source platform for the prototyping of diverse flow mechanisms. The developed simulation model describes the fully coupled mass balance equation and the chemical reaction of carbonate acidizing in an advection-diffusion regime. The volume of fluid (VOF) method is used to track the liquid- and gas-phase interface on fixed Eulerian grids. Here, the penalization method is applied to describe the wettability condition on immersed boundaries. The equations of saturation, concentration, and diffusion are solved successively, and the momentum equation is solved by pressure implicit with splitting of operators method. The simulation results of the developed numerical model have been validated with experimental results. Various injection velocities and the second Damkohler numbers have been examined to investigate their impacts on the CO2 bubble generation, evolving porosity, and rock surface area. We categorized the evolving carbon dioxide (CO2) distribution into three patterns in terms of the Damkohler number and the Péclet number. We also simulated a geometry model with multiple grains and a Darcy-scale model using the input parameters found from the pore-scale simulations. The newly developed pore-scale model provides the fundamental knowledge of physical and chemical phenomena of acid-rock interaction and their impact on acid transport. The modeling results describing mineral acidization will help us implement a practical fracturing project.

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