Axial Fracture Initiation During Diagnostic Fracture Injection Tests and Its Consequences on Interpretations

2021 ◽  
Author(s):  
Yuzhe Cai ◽  
Arash Dahi Taleghani ◽  
Rui Wang
Keyword(s):  
Flow Model ◽  
Fracture Initiation ◽  
Horizontal Stress ◽  
Potential Method ◽  
Closure Stress ◽  
Axial Fracture ◽  
Coupled Geomechanics ◽  
Maximum Horizontal Stress ◽  
Transverse Fractures ◽  
Fully Coupled

Abstract Diagnostic fracture injection tests (DFIT) are used widely in the unconventional reservoirs to obtain formation properties. These properties can be crucial in optimizing primary and infill completions. The interpretation methods are assuming that pumping fluid would create a single planar fracture, however, perforation frictions and near wellbore stress concentration may accommodate initiation of fractures along the casing first (axial fractures). The possibility of the formation of an axial fracture increases in high injection rates and low differential stresses. In this study, we investigate the effect of the formation of an additional axial fracture on a DFIT test and its interpretation, using a fully coupled geomechanics and fluid flow model. We provide a model for the initiation and closure of axial and transverse fractures during the process. We also demonstrate that the estimate of the closure stress can be misleading when presence of an additional axial fracture is ignored. Finally, we discuss a potential method to determine the maximum horizontal stress under such circumstances. In fact, the variations in cement quality, cement type and its placement play roles in linking of adjacent perforations and form axial fractures, therefore it might be difficult to establish a safe perforation design to avoid initiation of axial fractures, but we can adjust our analysis to incorporate axial fractures effect.

Horizontal Water Injection Wells: Injectivity and Containment of Injection-Induced Fractures

2021 ◽  
Author(s):  
Jongsoo Hwang ◽  
Mukul Sharma ◽  
Maria-Magdalena Chiotoroiu ◽  
Torsten Clemens
Keyword(s):  
Horizontal Well ◽  
Water Injection ◽  
Fracture Initiation ◽  
Horizontal Stress ◽  
Operating Conditions ◽  
Critical Factors ◽  
Injection Wells ◽  
Stress Direction ◽  
Maximum Horizontal Stress ◽  
Transverse Fractures

Abstract Horizontal water injection wells have the capacity to inject larger volumes of water and have a smaller surface footprint than vertical wells. We present a new quantitative analysis on horizontal well injectivity, injection scheme (matrix vs. fracturing), and fracture containment. To precisely predict injector performance and delineate safe operating conditions, we simulate particle plugging, thermo-poro-elastic stress changes, thermal convection and conduction and fracture growth/containment in reservoirs with multiple layers. Simulation results show that matrix injection in horizontal wells continues over a longer time than vertical injectors as the particle deposition occurs slowly on the larger surface area of horizontal wellbores. At the same time, heat loss occurs uniformly over a longer wellbore length to cause less thermal stress reduction and delay fracture initiation. As a result, the horizontal well length and the injection rates are critical factors that control fracture initiation and long-term injectivity of horizontal injectors. To predict fracture containment accurately, thermal conduction in the caprock and associated thermal stresses are found to be critical factors. We show that ignoring these factors underestimates fracture height growth. Based on our simulation analysis, we suggest strategies to maintain high injectivity and delay fracture initiation by controlling the injection rate, temperature, and water quality. We also provide several methods to design horizontal water injectors to improve fracture containment considering wellbore orientation relative to the local stress orientations. Well placement in the local maximum horizontal stress direction induces longitudinal fractures with better containment and less fracture turning than transverse fractures. When the well is drilled perpendicular to the maximum horizontal stress direction, the initiation of transverse fractures is delayed compared with the longitudinal case. Flow control devices are recommended to segment the flow rate and the wellbore. This helps to ensure uniform water placement and helps to keep the fractures contained.

A Novel Method and its Application to Define Maximum Horizontal Stress and Stress Path

2021 ◽  
Author(s):  
Jianguo Zhang ◽  
Karthik Mahadev ◽  
Stephen Edwards ◽  
Alan Rodgerson
Keyword(s):  
Fracture Initiation ◽  
Stress Path ◽  
Horizontal Stress ◽  
Geomechanical Model ◽  
Breakdown Pressure ◽  
In Situ Stresses ◽  
Fracture Closure ◽  
Minimum Horizontal Stress ◽  
Maximum Horizontal Stress

Abstract Maximum horizontal stress (SH) and stress path (change of SH and minimum horizontal stress with depletion) are the two most difficult parameters to define for an oilfield geomechanical model. Understanding these in-situ stresses is critical to the success of operations and development, especially when production is underway, and the reservoir depletion begins. This paper introduces a method to define them through the analysis of actual minifrac data. Field examples of applications on minifrac failure analysis and operational pressure prediction are also presented. It is commonly accepted that one of the best methods to determine the minimum horizontal stress (Sh) is the use of pressure fall-off analysis of a minifrac test. Unlike Sh, the magnitude of SH cannot be measured directly. Instead it is back calculated by using fracture initiation pressure (FIP) and Sh derived from minifrac data. After non-depleted Sh and SH are defined, their apparent Poisson's Ratios (APR) are calculated using the Eaton equation. These APRs define Sh and SH in virgin sand to encapsulate all other factors that influence in-situ stresses such as tectonic, thermal, osmotic and poro-elastic effects. These values can then be used to estimate stress path through interpretation of additional minifrac data derived from a depleted sand. A geomechanical model is developed based on APRs and stress paths to predict minifrac operation pressures. Three cases are included to show that the margin of error for FIP and fracture closure pressure (FCP) is less than 2%, fracture breakdown pressure (FBP) less than 4%. Two field cases in deep-water wells in the Gulf of Mexico show that the reduction of SH with depletion is lower than that for Sh.

Numerical Simulation and Laboratory Experiments of Hydraulic Fracturing of Highly Deviated Well

2013 ◽  
Vol 275-277 ◽  
pp. 278-281 ◽  
Author(s):  
Hai Yan Zhu ◽  
Jing Gen Deng ◽  
Song Yang Li ◽  
Zi Jian Chen ◽  
Wei Yan ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Hydraulic Fracturing ◽  
Fracture Initiation ◽  
Element Model ◽  
Simulation Method ◽  
Horizontal Stress ◽  
Initiation Point ◽  
Strength Failure ◽  
Fluid Penetration ◽  
Maximum Horizontal Stress

Considering the combined action of the fluid penetration and the casing, the seepage coupled deformation finite element model of the highly deviated casing perforation well is established by using the tensile strength failure criterion and applied on the BZ25-1 oil filed. The results show that the increasing of the perforation angle and the well azimuth and the decreasing of the inclination would lead to a higher fracture initiation pressure. The fracture initiation point always locates on the wellbore face when the influence of the casing is considered. When the casing is ignored: when the perforation angle is 0°-45°, the fracture initiation point locates on the root of the tunnel; when the angle is 45°-90°, the fracture initiation point may be on the wellbore face or the perforation biased toward the maximum horizontal stress direction; when the angle is near to 90°, the hydraulic fracturing difficultly fractures the rock through the perforation tunnels. The laboratory hydraulic fracturing simulation experiments of 45° deviated well are carried through 400mm3 cement specimen so as to obtain the fracture initiation point and geometric shape under different perforation angles, the results verify the accuracy of the numerical simulation method.

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