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.

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.

Utilizing Microseismic to Monitor Fracture Geometry in a Horizontal Well in a Tight Sandstone Formation

2021 ◽  
Author(s):  
Abu M. Sani ◽  
Hatim S. AlQasim ◽  
Rayan A. Alidi
Keyword(s):  
Horizontal Well ◽  
Fracture Propagation ◽  
Horizontal Stress ◽  
Height Growth ◽  
Tight Sandstone ◽  
Fracture Geometry ◽  
Fracture Length ◽  
Sandstone Formation ◽  
Fracture Height ◽  
Maximum Horizontal Stress

Abstract This paper presents the use of real-time microseismic (MS) monitoring to understand hydraulic fracturing of a horizontal well drilled in the minimum stress direction within a high-temperature high-pressure (HTHP) tight sandstone formation. The well achieved a reservoir contact of more than 3,500 ft. Careful planning of the monitoring well and treatment well setup enabled capture of high quality MS events resulting in useful information on the regional maximum horizontal stress and offers an understanding of the fracture geometry with respect to clusters and stage spacing in relation to fracture propagation and growth. The maximum horizontal stress based on MS events was found to be different from the expected value with fracture azimuth off by more than 25 degree among the stages. Transverse fracture propagation was observed with overlapping MS events across stages. Upward fracture height growth was dominant in tighter stages. MS fracture length and height in excess of 500 ft and 100 ft, respectively, were created for most of the stages resulting in stimulated volumes that are high. Bigger fracture jobs yielded longer fracture length and were more confined in height growth. MS events fracture lengths and heights were found to be on average 1.36 and 1.30 times, respectively, to those of pressure-match.

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.

scholarly journals Dynamics of clogging processes in injection wells used to pump highly mineralized thermal waters into the sandstone structures lying under the polish lowlands

2012 ◽  
Vol 38 (3) ◽  
pp. 105-117 ◽  
Author(s):  
Barbara Tomaszewska ◽  
Leszek Pająk
Keyword(s):  
Water Injection ◽  
Real Life ◽  
Injection Pressure ◽  
Operating Conditions ◽  
Solid Particles ◽  
Injection Well ◽  
Thermal Waters ◽  
Geothermal Systems ◽  
Injection Wells ◽  
Geothermal Resources

Abstract When identifying the conditions required for the sustainable and long-term exploitation of geothermal resources it is very important to assess the dynamics of processes linked to the formation, migration and deposition of particles in geothermal systems. Such particles often cause clogging and damage to the boreholes and source reservoirs. Solid particles: products of corrosion processes, secondary precipitation from geothermal water or particles from the rock formations holding the source reservoir, may settle in the surface installations and lead to clogging of the injection wells. The paper proposes a mathematical model for changes in the absorbance index and the water injection pressure required over time. This was determined from the operating conditions for a model system consisting of a doublet of geothermal wells (extraction and injection well) and using the water occurring in Liassic sandstone structures in the Polish Lowland. Calculations were based on real data and conditions found in the Skierniewice GT-2 source reservoir intake. The main product of secondary mineral precipitation is calcium carbonate in the form of aragonite and calcite. It has been demonstrated that clogging of the active zone causes a particularly high surge in injection pressure during the fi rst 24 hours of pumping. In subsequent hours, pressure increases are close to linear and gradually grow to a level of ~2.2 MPa after 120 hours. The absorbance index decreases at a particularly fast rate during the fi rst six hours (Figure 4). Over the period of time analysed, its value decreases from over 42 to approximately 18 m3/h/MPa after 120 hours from initiation of the injection. These estimated results have been confi rmed in practice by real-life investigation of an injection well. The absorbance index recorded during the hydrodynamic tests decreased to approximately 20 m3/h/MPa after 120 hours.

Some influences of stratigraphy and structure on reservoir stress orientation

Geophysics ◽  
1994 ◽  
Vol 59 (6) ◽  
pp. 954-962 ◽  
Author(s):  
Michael S. Bruno ◽  
Don F. Winterstein
Keyword(s):  
Principal Stress ◽  
Compressive Stress ◽  
Horizontal Stress ◽  
Oil Fields ◽  
Fold Axis ◽  
Principal Stresses ◽  
Stress Orientation ◽  
Stress Direction ◽  
Well Pattern ◽  
Maximum Horizontal Stress

The azimuth of maximum horizontal stress in a reservoir can vary significantly with depth and with position on a subsurface structure. We present and discuss evidence from field data for such variation and demonstrate both analytically and with finite‐element modeling how such changes might take place. Under boundary conditions of uniform far‐field displacement, changes in stratigraphic layering can reorient the principal stress direction if the formation is intrinsically anisotropic. If the formation stiffness is lower perpendicular to bedding than parallel to bedding (as is often the case in layered geologic media), an increase in dip will reduce the component of compressive stress in the dip azimuth direction. Folds can reorient principal stresses because flexural strain varies with depth and position. Compressive stress perpendicular to a fold axis increases with depth at the crest of an anticline and decreases with depth at the limb. When the regional stress anisotropy is weak, this change in stress magnitude can reorient the local principal stress directions. Numerical simulations of such effects gave results consistent with changes in stress orientation at the Cymric and Lost Hills oil fields in California as observed via shear‐wave polarization analyses and tiltmeter surveys of hydraulic fracturing. Knowledge of such variation of stress direction with depth and structural position is critical for drilling, completions, hydraulic fracture, and well pattern designs.

Design of Horizontal Wellbore in Dadas Shales of Turkey by Considering Wellbore Stability and Reservoir Geomechanics

2021 ◽  
Author(s):  
Sukru Merey ◽  
Can Polat ◽  
Tuna Eren
Keyword(s):  
Hydraulic Fracturing ◽  
Horizontal Well ◽  
Oil And Gas ◽  
Horizontal Wells ◽  
Horizontal Stress ◽  
Wellbore Stability ◽  
Horizontal Drilling ◽  
Horizontal Wellbore ◽  
Reservoir Geomechanics ◽  
Maximum Horizontal Stress

Abstract Currently, many horizontal wells are being drilled in Dadas shales of Turkey. Dadas shales have both oil (mostly) and gas potentials. Thus, hydraulic fracturing operations are being held to mobilize hydrocarbons. Up to 1000 m length horizontal wells are drilled for this purpose. However, there is not any study analyzing wellbore stability and reservoir geomechanics in the conditions of Dadas shales. In this study, the directions of horizontal wells, wellbore stability and reservoir geomechanics of Dadas shales were designed by using well log data. In this study, the python code developed by using Kirsch equations was developed. With this python code, it is possible to estimate unconfined compressive strength in along wellbore at different deviations. By analyzing caliper log, density and porosity logs of Dadas shales, vertical stress of Dadas shales was estimated and stress polygon for these shale was prepared in this study. Then, optimum direction of horizontal well was suggested to avoid any wellbore stability problems. According to the results of this study, high stresses are seen in horizontal directions. In this study, it was found that the maximum horizontal stress in almost the direction of North-South. The results of this study revealed that direction of maximum horizontal stress and horizontal well direction fluid affect the wellbore stability significantly. Thus, in this study, better horizontal well design was made for Dadas shales. Currently, Dadas shales are popular in Turkey because of its oil and gas potential so horizontal drilling and hydraulic fracturing operations are being held. However, in literature, there is no study about horizontal wellbore designs for Dadas shales. This study will be novel and provide information about the horizontal drilling design of Dadas shales.

A Model for Water Injection Into Frac-Packed Wells

2010 ◽  
Vol 13 (03) ◽  
pp. 449-464 ◽  
Author(s):  
Ajay Suri ◽  
Mukul M. Sharma
Keyword(s):  
Water Injection ◽  
Horizontal Stress ◽  
Injection Rate ◽  
Injection Wells ◽  
Solids Concentration ◽  
Sand Control ◽  
Injection Water ◽  
Large Injection ◽  
Minimum Horizontal Stress ◽  
Injection Rates

Summary Frac packs are increasingly being used for sand control in injection wells in poorly consolidated reservoirs. This completion allows for large injection rates and longer injector life. Many of the large offshore developments in the Gulf of Mexico and around the world rely on these completions for waterflooding and pressure maintenance. The performance of these injectors is crucial to the economics of the project because well intervention later in the life of the field is expensive and undesirable. For the first time, we present a model for water injection in frac-packed wells. The frac pack and the formation are plugged because of the deposition of particles from the injected water, and their effective permeability to water is continuously reduced. However, as the bottomhole pressure (BHP) reaches the frac-pack widening pressure, the frac-pack width increases and a channel that accommodates additional injected particles is created. Injectivity depends on the interstitial velocity of the injected water in the frac pack, volume concentration of the solids in the injected water, injection rate, injection-water temperature, size of proppants in the frac pack, width and length of the frac pack, and the initial minimum horizontal stress. In case of frac packs with large proppant size and high injection rates, the plugging of the frac pack is found to be negligible except in the building of a filter cake at the frac-pack walls. In the case of narrow frac packs with small proppant, significant plugging is expected, which leads to sharp permeability decline of the frac pack and a rapid rise in the BHP. The long-term injectivity of a frac-packed injector depends primarily on the filtration coefficient value of the frac pack, solids concentration in the injected water, and the injection rate. Frac packs are expected to maintain higher injectivities compared to any other completions such as openhole, cased-hole, perforated, or gravel packs.

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