scholarly journals Effects of Fracturing Parameters on Fracture Unevenness During Large-Stage Multi-Cluster Fracturing in Horizontal Wells

2021 ◽  
Vol 9 ◽  
Author(s):  
Rui Yong ◽  
Fu-Jian Zhou ◽  
Ming-Hui Li ◽  
Yi Song ◽  
Xiao-Jin Zhou ◽  
...  
Keyword(s):  
Fracture Propagation ◽  
Horizontal Wells ◽  
Hydrocarbon Reservoirs ◽  
Fluid Injection ◽  
Radial Pattern ◽  
Fracture Spacing ◽  
Fracture Length ◽  
Longmaxi Shale ◽  
Simulation Results ◽  
Single Cluster

Horizontal wellswith multi-cluster fracturing technology is an effective approach to exploit unconventional hydrocarbon reservoirs. The on-site diagnosis results indicate that multi-cluster fractures always tend to propagate unevenly due to stressinterference, therefore it is very essential to study the effect of fracturing parameters on fracture propagation unevenness. In this paper, the unconventional fracturing model (UFM, Unconventional Fracturing Model) is used to study the effect of multi-cluster fracturing parameters on fracture unevenness in a large stage. This model has been validated with the actual fracturing case on-site in the Longmaxi shale. The investigated parameters include completion parameters (cluster spacing, number of perforations per cluster), pumping parameters (fluid injection intensity and proppant injection intensity). Our simulation results show that firstly reducing fracture spacing will increase stress interference, andhydraulic fractures exhibit a “radial” pattern. Secondly, reducing the perforation number of a single cluster can promote the more uniform propagation of multi-cluster fractures. Thirdly, increasing the fluid injection intensity will increase the fracture length, but will also increase the fracture unevenness. Besides, the injection strength of the proppant has a little effect on the average fracture length and the unevenness of the fracture length. Finally, setting a reasonable cluster spacing and injection fluid strength can obtain a more uniform fracture propagation. Meanwhile reducing the number of perforations per cluster can also reach the goal of propagating evenly. This paper provides a certain reference for the optimization of multi-cluster fracturing parameters in large-stage and multi-cluster wells.

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.

Geomechanical Controls on Frac-Hits

2022 ◽  
Author(s):  
Dharmendra Kumar ◽  
Ahmad Ghassemi
Keyword(s):  
Pore Pressure ◽  
Fracture Propagation ◽  
Horizontal Wells ◽  
Operational Parameters ◽  
Modeling And Analysis ◽  
Matrix Deformation ◽  
In Situ Conditions ◽  
Fracture Fluid ◽  
Poroelastic Model ◽  
Element Method

Abstract The communication among the horizontal wells or "frac-hits" issue have been reported in several field observations. These observations show that the "infill" well fractures could have a tendency to propagate towards the "parent" well depending on reservoir in-situ conditions and operational parameters. Drilling the horizontal wells in a "staggered" layout with both horizontal and vertical offset could be a mitigation strategy to prevent the "frac-hits" issue. In this study, we present a detailed geomechanical modeling and analysis of the proposed solution. For numerical modeling, we used our state-of-the-art fully coupled poroelastic model "GeoFrac-3D" which is based on the boundary element method for the rock matrix deformation/fracture propagation and the finite element method for the fracture fluid flow. The "GeoFrac-3D" simulator fully couples pore pressure to stresses and allows for dynamic modeling of production/injection and fracture propagation. The simulation results demonstrate that production from a "parent’ well causes a non-uniform reduction of the reservoir pore pressure around the production fractures, resulting in an anisotropic decrease of the reservoir total stresses, which could affect fracture propagation from the "infill" wells. We examine the optimal orientation and position of the "infill" well based on the numerical analysis to reduce the "frac-hits" issue in the horizontal well refracturing. The posibility of "frac-hits" can be reduced by optimizing the direction and locations of the "infill" wells, as well as re-pressurizing the "parent" well. The results suggest that arranging the horizontal wells in a "staggered" or "wine rack" arrangement decreases direct well interference and could increase the drainage volume.

Parameters Optimization of Fractures with One for Injection and Two Others for Production of Horizontal Wells Fracturing on Offshore Oilfields

2014 ◽  
Vol 962-965 ◽  
pp. 489-493
Author(s):  
Zhi Qiang Li ◽  
Yong Quan Hu ◽  
Wen Jiang Xu ◽  
Jin Zhou Zhao ◽  
Jian Zhong Liu ◽  
...  
Keyword(s):  
Horizontal Well ◽  
Oil Production ◽  
Horizontal Wells ◽  
Simulation Method ◽  
Parameters Optimization ◽  
Development Mode ◽  
Fracture Conductivity ◽  
Fracture Length ◽  
Fractured Horizontal Well ◽  
Production Research

This article presents a new exploitation method based on the same fractured horizontal well with fractures for injection or production on offshore low permeability oilfields for the purpose of adapting to their practical situations and characteristics, which means fractures close to the toe of horizontal well used for injecting water and fractures near the heel of horizontal well used for producing oil. According to proposed development mode of fracturing, relevant physical model is established, Then reservoir numerical simulation method has been applied to study the effect of arrangement pattern of injection and production fractures, fracture conductivity, fracture length on oil production. Research indicates cumulative oil production is much higher by employing the middle fracture for injecting water compared with using the remote one, suggesting that the middle fracture adopted for injecting water, and hydraulic fracture length and conductivity have been optimized. The proposed development pattern of a staged fracturing for horizontal wells with some fractures applied for injecting water and others for production based on the same horizontal well provides new thoughts for offshore oilfields exploitation.

Best Practices in DFIT Interpretation: Comparative Analysis of 62 DFITs from Nine Different Shale Plays

2022 ◽  
Author(s):  
Mark Mcclure ◽  
Garrett Fowler ◽  
Matteo Picone
Keyword(s):  
Pressure Drop ◽  
Pore Pressure ◽  
Time Pressure ◽  
Early Time ◽  
Horizontal Wells ◽  
Late Time ◽  
Fracture Length ◽  
Well Spacing ◽  
Net Pressure ◽  
The Difference

Abstract In URTeC-123-2019, a group of operators and service companies presented a step-by-step procedure for interpretation of diagnostic fracture injection tests (DFITs). The procedure has now been applied on a wide variety of data across North and South America. This paper statistically summarizes results from 62 of these DFITs, contributed by ten operators spanning nine different shale plays. URTeC-123-2019 made several novel claims, which are tested and validated in this paper. We find that: (1) a ‘compliance method’ closure signature is apparent in the significant majority of DFITs; (2) in horizontal wells, early time pressure drop due to near-wellbore/midfield tortuosity is substantial and varies greatly, from 500 to 6000+ psi; (3) in vertical wells, early-time pressure drop is far weaker; this supports the interpretation that early- time pressure drop in horizontal wells is caused by near-wellbore/midfield tortuosity from transverse fracture propagation; (4) the (not recommended) tangent method of estimating closure yields Shmin estimates that are 100-1000+ psi lower than the estimate from the (recommended) compliance method; the implied net pressure values are 2.5x higher on average and up to 5-6x higher; (5) as predicted by theory, the difference between the tangent and compliance stress and net pressure estimates increases in formations with greater difference between Shmin and pore pressure; (6) the h-function and G-function methods allow permeability to be estimated from truncated data that never reaches late-time impulse flow; comparison shows that they give results that are close to the permeability estimates from impulse linear flow; (7) false radial flow signatures occur in the significant majority of gas shale DFITs, and are rare in oil shale DFITs; (8) if false radial signatures are used to estimate permeability, they tend to overestimate permeability, often by 100x or more; (9) the holistic-method permeability correlation overestimates permeability by 10-1000x; (10) in tests that do not reach late-time impulse transients, it is reasonable to make an approximate pore pressure estimate by extrapolating the pressure from the peak in t*dP/dt using a scaling of t^(-1/2) in oil shales and t^(3/4) in gas shales. The findings have direct practical implications for operators. Accurate permeability estimates are needed for calculating effective fracture length and for optimizing well spacing and frac design. Accurate stress estimation is fundamental to hydraulic fracture design and other geomechanics applications.

Role of fracture opening in triggering microseismicity observed during hydraulic fracturing

Geophysics ◽  
2019 ◽  
Vol 84 (3) ◽  
pp. KS105-KS118 ◽  
Author(s):  
Himanshu Barthwal ◽  
Mirko van der Baan
Keyword(s):  
Hydraulic Fracturing ◽  
Pore Pressure ◽  
Material Balance ◽  
Crack Tip ◽  
Hydrocarbon Reservoirs ◽  
Fluid Injection ◽  
Low Permeability ◽  
Stress Shadow ◽  
Pressure Diffusion ◽  
Microseismic Events

Hydraulic fracturing in low-permeability hydrocarbon reservoirs creates/reactivates a fracture network leading to microseismic events. We have developed a simplified model of the evolution of the microseismic cloud based on the opening of a planar fracture cavity and its effect on elastic stresses and pore pressure diffusion during fluid injection in hydraulic fracturing treatments. Using a material balance equation, we compute the crack tip propagation over time assuming that the hydraulic fracture is shaped as a single penny-shaped cavity. Results indicate that in low-permeability formations, the crack tip propagates much faster than the pore pressure diffusion front thereby triggering the microseismic events farthest from the injection domain at any given time during fluid injection. We use the crack tip propagation to explain the triggering front observed in distance versus time plots of published microseismic data examples from hydraulic fracturing treatments of low-permeability hydrocarbon reservoirs. We conclude that attributing the location of the microseismic triggering front purely to pore pressure diffusion from the injection point may lead to incorrect estimates of the hydraulic diffusivity by multiple orders of magnitude for low-permeability formations. Moreover, the opening of the fracture cavity creates stress shadow zones perpendicular to the principal fracture walls in which microseismic triggering due to the elastic stress perturbations is suppressed. Microseismic triggering in this stress shadow region may be attributed mainly to pore pressure diffusion. We use the width, instead of the longest size, of the microseismic cloud to obtain an enhanced diffusivity measure, which may be useful for subsequent production simulations.

scholarly journals Mechanical Property Measurements and Fracture Propagation Analysis of Longmaxi Shale by Micro-CT Uniaxial Compression

Energies ◽  
2018 ◽  
Vol 11 (6) ◽  
pp. 1409 ◽  
Author(s):  
Minyue Zhou ◽  
Yifei Zhang ◽  
Runqing Zhou ◽  
Jin Hao ◽  
Jijin Yang
Keyword(s):  
Mechanical Property ◽  
Uniaxial Compression ◽  
Fracture Propagation ◽  
Micro Ct ◽  
Propagation Analysis ◽  
Longmaxi Shale

Productivity Model and Production Decline Characteristics of Multi-Fracturing Horizontal Well

2015 ◽  
Vol 733 ◽  
pp. 3-8
Author(s):  
Peng Chen ◽  
Xin Hai Wang ◽  
Shan Jiang ◽  
Guo Liang Li ◽  
Hong Liu
Keyword(s):  
Horizontal Well ◽  
Early Stage ◽  
Superposition Principle ◽  
Early Period ◽  
Exponential Model ◽  
Fracture Spacing ◽  
Fracture Length ◽  
Well Production ◽  
Infinite Conductivity ◽  
The Relationship

By using the potential theory and the superposition principle, Productivity model of multi-fracturing horizontal well is established under the condition of infinite conductivity fractures. It solves the problem by using numerical methods and analyzes the influence of fracture numbers, fracture length and fracture spacing on well production by using actual reservoir parameters. Finally, it analyzes the production decline characteristics of multi-fracturing horizontal well based on the change of production curve. In the early period of production, the well production increases with the increase of fracture numbers, fracture length and fracture spacing. In the late period, the fracture parameters have less effect on well production. Early-stage production of multi-fracturing horizontal well obeys to the modified-hyperbolic decline model, while the relationship between ratio of Q, Qi and time is exponential model in the late-stage. It has some significance for design of horizontal well fracturing parameters and production forecasts in unconventional reservoirs.

Experimental Research on Electric Analogy of Staged Fracturing of Horizontal Wells Flooding

2014 ◽  
Vol 955-959 ◽  
pp. 3484-3488
Author(s):  
Guang Zhong Lv ◽  
Jiang Qiao Zhang
Keyword(s):  
Horizontal Well ◽  
Horizontal Wells ◽  
Experimental Conditions ◽  
Horizontal Section ◽  
Fracture Length ◽  
Unidirectional Flow ◽  
Horizontal Length ◽  
Fractured Horizontal Well ◽  
Well Pattern ◽  
Penetration Ratio

An electrolytic simulation experiment was designed according to the water and electricity resembling principle. The pressure contour distribution and the effects of the productivity of the fractured horizontal well were experimentally studied under the flooding. The equal pressure lines around horizontal wells were elliptic, and the equal pressure lines were Parallelled distribution in the fracture of horizontal well, Flow states was unidirectional flow, indicating staged fracturing of horizontal well by improving Percolation way greatly reduce seepage resistance. Under the experimental conditions, staged fracturing horizontal waterflooding development best combination of parameters: row and staggered well pattern, penetration ratio of horizontal section was 0.8, the number of fractures should be 6 (fracture space was 91m), penetration ratio of fracture was 0.25, the angle between the fracture and horizontal well is 90 degree. The importance ranking of productivity was horizontal length, the number of fractures (fracture space ),fracture length, he angle between the fracture and horizontal well and well-pattern type.

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