Impact of Pore Pressure on Modeled Hydraulic Fracture Geometry and Well Spacing in the East Duvernay Shale Basin, Canada

2019 ◽  
Author(s):  
Farhan Alimahomed ◽  
Eric Wigger ◽  
Matthew Drouillard ◽  
Gabriel Garcia Rosas ◽  
Christen Kolbeck
Keyword(s):  
Pore Pressure ◽  
Hydraulic Fracture ◽  
Fracture Geometry ◽  
Well Spacing

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.

Impact of Geomechanics on Well Completion and Asset Development in the Bakken Formation

2015 ◽  
Author(s):  
Sameer Ganpule ◽  
Karthik Srinivasan ◽  
Tyler Izykowski ◽  
Barbara Luneau ◽  
Ernest Gomez
Keyword(s):  
Pore Pressure ◽  
Hydraulic Fracture ◽  
Normal Pressure ◽  
In Situ Stress ◽  
Stress Profile ◽  
Well Spacing ◽  
Pressure Profiles ◽  
Asset Development ◽  
Pressure Regime

Abstract In-situ stress variability within a reservoir is a primary parameter that controls hydraulic fracture initiation, growth, connectivity, and ultimately drainage and well spacing. This paper highlights the importance of characterizing the variability of in-situ stress and demonstrates the risk of underestimating stimulation treatment size when a treatment design is applied in a “copy-paste” fashion without any modifications to account for variation in pore pressure and in-situ stress across a basin. Thermal maturity and hydrocarbon generation from unconventional shales has a direct effect on pore pressure and the in-situ stress distribution in reservoir and barrier rocks. An examination of the Bakken Petroleum System (BPS) identifies regions of thermal maturity and higher pore pressure due to hydrocarbon expulsion. Consequently, the elevated pore pressure and the resulting in-situ stress vary vertically and laterally within the basin. Multiple pore pressure profiles and corresponding stress profiles across the BPS were considered to quantify the impact of in-situ stress variability on hydraulic fracture geometry. These profiles include effects of normal pore pressure regime, over-pressure regime or pressure profiles transitioning from over pressure to normal pressure regimes. For a given stress profile, hydraulic fracture geometries are estimated using a fracture simulator, with multiple calibration points. The hydraulic fracture system and reservoir interactions are simulated in a subsequent production modeling phase which estimates drainage area characteristics, recovery forecasts and optimum well spacing for developing an asset. Results from stress profile sensitivity emphasize the need to address variability of in-situ stress as it directly impacts well spacing considerations in an asset development plan. For example, stress profile with a normal pore pressure regime results in longer hydraulic fracture lengths in the Middle Bakken (MB) thus requiring three wells per section to infill the asset. Conversely, stress profile with over-pressure regime in MB results in much shorter hydraulic fracture lengths thus requiring more than three wells per section to develop the asset. Incorrectly assuming overpressure in a normally pressured zone could lead to over-engineering of wells and unnecessary costs, whereas incorrectly assuming normal pressure in zones that are in fact overpressured could lead to sub-optimal completions and/or a reduction in overall production.

Hydraulic Fracture Containment: New Insights Into Mapped Geometry

2015 ◽  
Author(s):  
C.J.. J. de Pater
Keyword(s):  
Pore Pressure ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Ground Truth ◽  
Height Growth ◽  
Propagation Model ◽  
Fracture Geometry ◽  
Fracture Length ◽  
Propagation Modeling ◽  
Fracture Mapping

Abstract Recently, fracture mapping has contributed a vast amount of data on hydraulic fracture geometry showing in general a fairly strong containment of fractures, but it is unclear what explains observed height containment. Re-analysis of published fracture mapping data yields a rule-of-thumb for expected fracture geometry and gives insight into the role of reservoir pressure in the observed containment. Fracture containment is important for designing stimulation treatments that cover the entire pay, without breaching into aquifers or gas caps. Although modern fracture mapping provides the ground truth for post-treatment fracture geometry, it is still important to forecast fracture height growth based on pre-treatment data. Fracture mapping shows that on average, fracture length is five times height. Some, (often depleted) reservoirs show even more extreme containment effects. In addition to stress differences, new mechanisms have been proposed to explain the strong observed containment, such as layer interface opening. Although such mechanisms are quite plausible in some formations, it is unlikely that they provide a universal explanation. New developments in fracture propagation modeling provide a simple mechanism for stronger containment than predicted by conventional models. Laboratory testing indicates that fracture propagation must be described by a cohesive zone at the tip. In such a model, rock ruptures at the fracture tip due to effective stress exceeding strength, which introduces the difference between stress and pore pressure into fracture propagation (Schmitt et al., 1989; Visser, 1998). In the first place this propagation model readily explains high net pressure, while a relatively small stress difference can yield much slower height growth compared with length growth. Furthermore, pore pressure changes upon failure can yield a strong containment effect.

scholarly journals The Effect of Hydraulic Fracture Geometry on Well Productivity in Shale Oil Plays with High Pore Pressure

Energies ◽  
2021 ◽  
Vol 14 (22) ◽  
pp. 7727
Author(s):  
Daniela A. Arias Ortiz ◽  
Lukasz Klimkowski ◽  
Thomas Finkbeiner ◽  
Tadeusz W. Patzek
Keyword(s):  
Pore Pressure ◽  
Hydraulic Fracture ◽  
Hydraulic Fractures ◽  
Shale Oil ◽  
Production Forecast ◽  
Fracture Geometry ◽  
Hydrocarbon Production ◽  
Reservoir Simulations ◽  
Bedding Planes

We propose three idealized hydraulic fracture geometries (“fracture scenarios”) likely to occur in shale oil reservoirs characterized by high pore pressure and low differential in situ stresses. We integrate these geometries into a commercial reservoir simulator (CMG-IMEX) and examine their effect on reservoir fluids production. Our first, reference fracture scenario includes only vertical, planar hydraulic fractures. The second scenario has stimulated vertical natural fractures oriented perpendicularly to the vertical hydraulic fractures. The third fracture scenario has stimulated horizontal bedding planes intersecting the vertical hydraulic fractures. This last scenario may occur in mudrock plays characterized by high pore pressure and transitional strike-slip to reverse faulting stress regimes. We demonstrate that the vertical and planar fractures are an oversimplification of the hydraulic fracture geometry in anisotropic shale plays. They fail to represent the stimulated volume geometric complexity in the reservoir simulations and may confuse hydrocarbon production forecast. We also show that stimulating mechanically weak bedding planes harms hydrocarbon production, while stimulated natural fractures may enhance initial production. Our findings reveal that stimulated horizontal bedding planes might decrease the cumulative hydrocarbon production by as much as 20%, and the initial hydrocarbon production by about 50% compared with the reference scenario. We present unique reservoir simulations that enable practical assessment of the impact of varied hydraulic fracture configurations on hydrocarbon production and highlight the importance of constraining present-day in situ stress state and pore pressure conditions to obtain a realistic hydrocarbon production forecast.

Data Analytics to Help Improve Hydraulic Fracture Geometry Prediction Using Support Vector Regression: Case Study

2020 ◽  
Author(s):  
Avinash Wesley ◽  
Bharat Mantha ◽  
Ajay Rajeev ◽  
Aimee Taylor ◽  
Mohit Dholi ◽  
...  
Keyword(s):  
Support Vector Regression ◽  
Hydraulic Fracture ◽  
Data Analytics ◽  
Support Vector ◽  
Fracture Geometry

4D Geomechnical Model Creation for Estimation of Field Development Effect on Hydraulic Fracture Geometry (Russian)

2016 ◽  
Author(s):  
Valeriy Pavlov ◽  
Evgeny Korelskiy ◽  
Kreso Kurt Butula ◽  
Artem Kluybin ◽  
Danil Maximov ◽  
...  
Keyword(s):  
Hydraulic Fracture ◽  
Fracture Geometry ◽  
Field Development

Comprehensive Characterization and Mitigation of Hydraulic Fracturing-Induced Seismicity in Fox Creek, Alberta

SPE Journal ◽  
2021 ◽  
pp. 1-12
Author(s):  
Gang Hui ◽  
Shengnan Chen ◽  
Zhangxin Chen ◽  
Fei Gu ◽  
Mathab Ghoroori ◽  
...  
Keyword(s):  
Spatial Distribution ◽  
Hydraulic Fracturing ◽  
Pore Pressure ◽  
Hydraulic Fracture ◽  
Induced Seismicity ◽  
Mitigation Strategy ◽  
Moment Magnitude ◽  
Induced Earthquakes ◽  
Data Set ◽  
Comprehensive Characterization

Summary The relationships among formation properties, fracturing operations, and induced earthquakes nucleated at distinctive moments and positions remain unclear. In this study, a complete data set on formations, seismicity, and fracturing treatments is collected in Fox Creek, Alberta, Canada. The data set is then used to characterize the induced seismicity and evaluate its susceptibility toward fracturing stimulations via integration of geology, geomechanics, and hydrology. Five mechanisms are identified to account for spatiotemporal activation of the nearby faults in Fox Creek, where all major events [with a moment magnitude (Mw) greater than 2.5] are caused by the increase in pore pressure and poroelastic stress during the fracturing operation. In addition, an integrated geological index (IGI) and a combined geomechanical index (CGI) are first proposed to indicate seismicity susceptibility, which is consistent with the spatial distribution of induced earthquakes. Finally, mitigation strategy results suggest that enlarging a hydraulic fracture-fault distance and decreasing a fracturing job size can reduce the risk of potential seismic activities.

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