Hydraulic Fracture Treatment Designs: Distillation and Integration of Best Practices in the Spraberry and Wolfcamp Formations of the Permian Basin

2018 ◽  
Author(s):  
Amro Abdelrahman Ahmed Othman ◽  
Abiodun Matthew Amao
Keyword(s):  
Best Practices ◽  
Hydraulic Fracture ◽  
Fracture Treatment ◽  
Permian Basin ◽  
Treatment Designs

A Multi-Disciplinary Approach for Well Spacing and Treatment Design Optimization in the Midland Basin Using Lateral Pore Pressure Estimation and Depletion Modeling

2021 ◽  
Author(s):  
Taylor Levon ◽  
Kit Clemons ◽  
Ben Zapp ◽  
Tim Foltz
Keyword(s):  
Pore Pressure ◽  
Hydraulic Fracture ◽  
Initial Study ◽  
Midland Basin ◽  
Well Spacing ◽  
Fracture Modeling ◽  
Original Target ◽  
Treatment Responses ◽  
Treatment Designs

Abstract With a recent trend in increased infill well development in the Midland basin and other unconventional plays, it has been shown that depletion has a significant impact on hydraulic fracture propagation. This is largely because production drawdown causes in-situ stress changes, resulting in asymmetric fracture growth toward the depleted regions. In turn, this can have a negative impact on production capacity. For the initial part of this study, an infill child well was drilled and completed adjacent to a parent well that had been producing for two years. Due to drilling difficulties, the child well was steered to a new target zone located 125 feet above the original target. However, relative to the original target, treatment data from the new zone indicated abnormal treatment responses leading to a study to evaluate the source of these variations and subsequent mitigation. The initial study was conducted using a pore pressure estimation derived from drill bit geomechanics data to investigate depletion effects on the infill child well. The pore pressure results were compared to the child well treatment responses and bottom hole pressure measurements in the parent well. Following the initial study, additional hydraulic fracture modeling studies were conducted on a separate pad to investigate depletion around the infill wells, determine optimal well spacing for future wells given the level of depletion, and optimize treatment designs for future wells in similar depletion scenarios. A depletion model workflow was implemented based on integrating hydraulic fracture modeling and reservoir analytics for future infill pad development. The geomechanical properties were calibrated by DFIT results and pressure matching of the parent well treatments for the in-situ virgin conditions. Parent well fracture geometries were used in an RTA for an analytical approach of estimating drainage area of the parent wells. These were then applied to a depletion profile in the hydraulic fracture model for well spacing analysis and treatment design sensitivities. Results of the initial study indicated that stages in the new, higher interval had higher breakdown pressures than the lower interval. Additionally, the child well drilled in the lower interval had normal breakdown pressures in line with the parent well treatments. This suggests that treatment differences in the wells were ultimately due to depletion of the offset parent well. Based on the modeling efforts, optimal infill well spacing was determined based on the on-production time of the parent wells. The optimal treatment designs were also determined under the same conditions to minimize offset frac hits and unnecessary completion costs. This case study presents the use of a multi-disciplinary approach for well spacing and treatment optimization. The integration of a novel method of estimating pore pressure and depletion modeling workflows were used in an inventive way to understand depletion effects on future development.

Evaluating Fracturing Fluid Flowback in Marcellus Using Data Mining Technologies

2015 ◽  
Author(s):  
Qiumei Zhou ◽  
Robert Dilmore ◽  
Andrew Kleit ◽  
John Yilin Wang
Keyword(s):  
Hydraulic Fracture ◽  
Marcellus Shale ◽  
Production Data ◽  
Fracture Treatment ◽  
Water Recovery ◽  
Flowback Water ◽  
Gas Recovery ◽  
Well Completion ◽  
Geological Conditions ◽  
Fracture Fluid

Abstract Natural gas recovery from low permeability unconventional reservoirs – enabled by advanced horizontal drilling and multi-stage hydraulic fracture treatment - has become a very important energy resource in the past decade. While evaluating early gas production data in order to assess likely rate decline and ultimate gas recovery has been reported in literature, flowback water recovery has been given little consideration. Fracture fluid flowback is defined herein as aqueous phase produced within three weeks following a fracture treatment (exclusive of well shut-in time). Field data from Marcellus Shale wells in Northeastern West Virginia indicated about 2-26% of the fracture fluid is recovered during flowback. However, stimulation of gas shale is a complex engineered process, and the factors that control the volumetric flowback performance are not well understood. The objective of this paper is to use post-hoc analysis to identify correlations between fracture fluid flowback and attributes of well completion and geological setting, and to identify those factors most important in predicting flowback performances. To accomplish this objective we selected a representative subset of 187 wells for which complete data are available (from a full set of 631 wells), including well location, completion data, hydraulic fracture treatment data and production data. The wells were classified into four groups based on geological settings. For each geological group, engineering and statistical analyses were applied to study the correlation between flowback data and well completion through traditional regression methods. Important factors considered to affect flowback water recovery efficiency include number of hydraulic fracture stages, lateral length, vertical depth, proppant mass applied, proppant size, fracture fluid volume applied, treatment rate, and shut-in time. The total proppant mass, proppant size and shut-in time have relatively large influence on volumetric flowback performance. The new results enable one to estimate flowback volume in a spatial domain, based on known geological conditions and completion parameters, and lead to a better understanding of flowback behaviors in Marcellus Shale. This also helps industry manage flowback water and optimize production operations.

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