bluuebunny/crossref_metadata_2025_split huggingface dataset:
Three-Dimensional Analysis of Interactions Between Hydraulic and Natural Fractures
Authors: Daneshy Ali 
Published: January 2019

Abstract
Understanding the effect of natural fractures on the propagation of a hydraulic fracture has challenged the fracturing community for a very long time. Nearly all previous investigations address the problem with the assumption that the natural and hydraulic fractures are all vertical and basically two-dimensional. While it is realistic to assume that the hydraulic fractures are vertical, the natural fractures have random orientations, and many of them are not in a vertical plane.
This paper offers a first look at the 3D interactions between a vertical hydraulic fracture and randomly oriented natural fractures. It computes the stresses acting on the natural fractures induced by the three in-situ principal stresses plus an actively growing hydraulic fracture. It shows that as the inclination of the natural fracture with respect to the vertical plane increases, the chances of its activation by a hydraulic fracture diminishes, with a horizontal natural fracture having a very low chance of activation.
Natural fractures are divided into three general groups; open, closed unbonded, and closed bonded. Activation of each of these general groups are reviewed separately and factors that control the process are identified and discussed.
Paper shows that when an advancing hydraulic fracture intersects an open natural fracture, the initial result is local fracture arrest. Next, the hydraulic fracture grows three-dimensionally around the natural fracture and joins it from the opposite side. Continuous three-dimensional growth of the hydraulic fracture increases the fluid pressure inside the open natural fracture and can cause initiation of a branch fracture from one or more of its extremities. The net result is creation of a main fracture together with a set of smaller and very narrow offset branch fractures.
An unbonded closed natural fracture has no tensile strength and can open when exposed to a tensile normal stress acting on its face. Intersection of these types of natural fractures by a hydraulic fracture can have one or more of three different consequences; crossing through, limited natural fracture opening in mixed mode (tensile plus shear) and extension, or creation of offset parallel branches. The conditions leading to each of these are identified and discussed.
Bonded closed natural fractures can activate if the magnitude of the tensile stress induced on its face by the advancing hydraulic fracture causes the normal stress on its face to exceed its bond strength. In this situation the activation of the natural fracture will be in mixed more (tensile plus shear). However, under most actual situations hydraulic fractures are more likely to cross through them.
The important parameters controlling activation of natural fractures are their inclination angle with respect to the hydraulic fracture and the three in-situ principal stresses, the magnitude of fluid pressure inside the fracture relative to the difference between the two horizontal principal stresses, and their size and location.
Got Diversion? Real Time Analysis to Identify Success or Failure
Authors: Trumble Michael , Sinkey Matthew , Meehleib Jeremy 
Published: January 2019

Abstract
Successful diversion is traditionally identified as a sudden treating pressure increase upon the diverter material reaching the perforations. However, the real value is derived from sustaining that diversion for subsequent proppant placement. The charting overlay approach focuses on that sustained diversion. With validation from fiber optic data, the overlay method has a proven track record of real-time diagnostics, eliminating the need for time-consuming, resource intensive high cost evaluations. That real-time application allows treatments to be confidently optimized while pumping, increasing stimulation effectiveness and operational efficiencies.
Through the process of overlaying treating pressures before and after diversion, the effectiveness of the diverter can be qualified and adjustments made for subsequent diverter drops. The charting overlay method, which consists of plotting early time treatment data on top of later treatment data, provides better accuracy and a more thorough analysis than the traditional method of evaluating pressure increase, or ‘hit’ pressure, when diverter arrives on formation. When compared to fiber optic data utilizing a dynamic acoustic sensing (DAS) tool, the charting overlay method indicated successful diversion every time the DAS data showed diversion from cluster to cluster. The comparison with the DAS data further proved that the charting overlays can be used for real-time diversion analysis.
This method is useful to those who are using diverting agents to create more efficient stimulation. Through the use of the charting overlay technique, diversion strategies can be adjusted real-time to improve the diversion and increase cluster efficiency.
The Role of Micro-Proppants in Conductive Fracture Network Development
Authors: Kumar Dharmendra , Gonzalez Ruben A. , Ghassemi Ahmad 
Published: January 2019

Abstract
Micro-proppants use in hydraulic fracturing has had a significant impact on production and has led to a reduction of treating pressure and thus enhancement of the overall hydraulic fracturing treatment. A number of mechanisms have been proposed to explain the success of micro-proppants. However, the role of these proppants on increasing the conductivity of secondary natural fractures and fracture network development has not been well demonstrated. The objective of this paper is to explore and clarify the potential mechanisms involved in the success of micro-proppants. We study the transport and deposition of micro-proppants in propagating facture networks using an advanced simulator "GeoFrac-3D" that can consider irregular fracture geometries and intersection angles not limited to 90 degrees, thereby capturing realistic flow and proppant transport pathways and deposition sites. The method is 3D and fully couples fluid pressure to stresses and allows for dynamic modeling of 3D fracture propagation. Robust multiple 3D fracture propagation is considered using the displacement discontinuity method for the rock deformation and the finite element method for the fracture fluid flow. The pressure dependent leak-off of the fracturing fluid into the rock matrix/natural fracture system is considered. The proppant transport and deposition within the fracture is modeled by treating the mixture of fluid and proppant particles as slurry. The simulation results show that proppant transport into secondary fractures, and relatively less settling are the major factors in micro-proppant effectiveness. Proppant settling velocities and thus proppant distribution is affected by fluid velocity, micro-proppant size, fluid rheology, fracture aperture, hydraulic and natural fracture interaction and near wellbore tortuosity. The results demonstrates that the micro-proppants being smaller size particles have strong potential for the effective uniform proppant placement into the complex fractured unconventional reservoirs; hence, to increase their conductivity for the oil and gas in-flow. Additionally, as the micro-proppant can enter into the tight natural or secondary fractures, it will reduce pressure dependent leak-off of the fracturing fluid into the surrounding formation, which will result in reduction in treating pressure.
Preventing Heel Dominated Fractures in Horizontal Well Refracturing
Authors: Yi Sophie , Manchanda Ripudaman , Sharma Mukul , Roussel Nicolas 
Published: January 2019

Abstract
Horizontal-well refracturing is important in the development of unconventional plays to improve the productivity of the refraced well and to protect parent wells from the fractures propagating from the nearby child wells. In the field, heel-biased fracture propagation is frequently observed in refracturing treatments, leaving a large fraction the wellbore understimulated. In this paper, we explain the mechanisms of heel-biased fracture propagation and suggest strategies to mitigate such behavior.
We model refracturing operations accounting for reservoir geomechanics, wellbore hydrodynamics, completion strategies, as well as near-wellbore effects. A coupled reservoir geomechanics simulator is used to calculate the poroelastic stress changes in the reservoir due to production. Then, a multi-fracture simulator with newly developed wellbore fluid and proppant transport model is applied to simulate the refracturing process. A field refrac case is simulated and the simulation results show good agreement with field diagnostics including proppant distribution among multiple fractures. The simulation results help us understand the mechanisms behind heel-biased fracture propagation in refractured wells and allow us to investigate strategies to improve refrac treatment efficiency.
The mechanisms affecting treatment distribution in refracs are investigated from two perspectives: the non-uniform pore pressure and stress profile in the reservoir, and the wellbore hydrodynamics. The latter perspective studies the fluid and proppant transport and separation in the wellbore. With the long wellbore length and the large number of open fractures, the impact of wellbore hydrodynamics on the refrac treatment distribution is very important. Wellbore friction is believed to be a minor reason for the heel-biased treatment distribution compared to proppant inertia, which could lead to the pre-mature screen out of the toe-side clusters.
Simulation results show that using small refrac stages with more frequent diverting agent application can help avoid over-stimulating the dominant fractures and promote more uniform fracture propagation. Strategies that moderate the proppant inertia could also help mitigate the heel-biased trend of refrac treatment distribution.
A Novel Approach for Estimating Formation Permeability and Revisit After-Closure Analysis from DFIT
Authors: Wang HanYi , Sharma Mukul M. 
Published: January 2019

Abstract
Estimating reservoir flow capacity is crucial for production estimation, hydraulic fracturing design and field development. Laboratory experiments can be used to measure the permeability of rock samples, but the results may not be representative at a field scale because of reservoir heterogeneity and pre-existing natural fracture systems. Diagnostic Fracture Injection Tests (DFIT) have now become standard practice to estimate formation pore pressure and formation permeability. However, in low permeability reservoirs, after-closure radial flow is often absent and this can cast significant uncertainties in interpreting DFIT data. In addition, the established methods for analyzing DFIT data make two oversimplified assumptions: (1) Carter's leak-off and, (2) Constant fracture compliance (or stiffness) during fracture closure. However, both assumptions are violated during fracture closure and this is why G-function based models and subsequent related works can lead to an incorrect interpretation and are not capable of consistently fitting both before and after closure data coherently (Wang and Sharma 2017). Moreover, current after-closure analysis relies on classic well-test solutions with constant injection rate. In reality, a "constant injection rate" does not equal "constant leak-off rate into the formation", because over 90% of the injected fluid stays inside the fracture at the end of pumping, instead of leaking into formation. The variable leak-off rate clearly violates the constant rate boundary condition used in existing well-test solutions.
In this study, we extend our previous work and derive time-convolution solutions to pressure transient behavior of a closing fracture with infinite and finite fracture conductivity. We show that G-function and the square root of time models are only special cases of our general solutions. In addition, we found that after-closure linear flow and bilinear flow analysis can only be used to infer pore pressure reliably, but fail to estimate other parameters correctly. Most importantly, we present a new approach to history match the entire duration of DFIT data to estimate formation flow capacity, even without knowing closure stress and the roughness properties of the fracture surface. Our approach adds tremendous value to DFIT interpretation and uncertainty analysis, especially in unconventional reservoirs where the absence of after-closure radial flow is the norm. Two representative field cases are also presented and discussed.
Three-Dimensional Effects of Reservoir Depletion on Hydraulic Fracture Propagation
Authors: Huang Jixiang , Fu Pengcheng , Hao Yue , Morris Joseph , Settgast Randolph , Ryerson Frederick 
Published: January 2019

Abstract
Reservoir depletion and its influence on subsequent hydraulic fracture propagation are studied using a three-dimensional fully coupled geomechanics, fluid flow and hydraulic fracturing code. Pressure change and resultant stress alteration are captured through a rigorously developed poroelastic model, validated against analytical solutions. In the context of parent-child well interference, depletion-induced stress reduction will attract fracturing from nearby wells, unfavorably affecting production of the parent well in most cases by leaving the target region unstimulated or understimulated. One engineering practice to remedy this impact is to refracture the parent well before fracturing in child wells. How this treatment impacts the fracturing and to what extent it can prevent the attraction have been quantitatively studied using the geomechanics-flow coupling and hydraulic fracturing capabilities within a unified framework. Sensitivity studies of matrix permeability, production time and fracture spacing have been performed to explore the feasibility of controlled fracture growth into a depletion region. The amount of fluid required to refracture the producing well sufficiently to create a stress barrier that inhibits deletarious growth of child fractures depends on the degree of reservoir depletion. A complex scenario involving the interactions between reservoir depletion, refracturing and geologic factors such as stress barriers is also studied. The possibility for a subsequent fracturing to break through a stress barrier after a certain time of production, which would otherwise be impossible, is explored, indicating a potential parent-child well interference mechanism even when the parent and child wells are located in different formations. This phenomenon is essentially three dimensional and has not been captured by previous studies.
Numerical Simulation of DFITs Within a Coupled Reservoir Flow and Geomechanical Simulator - Insights Into Completions Optimization
Authors: Ji Lujun , Sen Vikram , Min Kyoung Suk , Sullivan Richard 
Published: January 2019

Abstract
A novel DFIT simulator comprising a 3D hydraulic fracturing model seamlessly coupled within one software with reservoir flow and geomechanical modeling is described and used to numerically analyze DFITs in unconventional reservoirs. This workflow involves history matching treatment or injection pressures (fracture propagation) and shut-in (fracture closure) pressures consistent with 3D growth of hydraulic fractures in the presence of pressure dependent leak-off. These are the same fundamental processes which characterize Dynamic Stimulated Reservoir Volume or DSRV growth (Sen et al., 2018, Min et al., 2018) and DFITs can therefore be used to get a better early prognosis on the potential of DSRV growth in a tight reservoir.
This modular DFIT simulator iteratively couples a finite-difference reservoir simulation with a finite- element geomechanical modeling within one software and can therefore maintain important consistencies between fracture opening, propagation, closure and the stress dependent leak-off and permeability evolution inside the induced dynamic SRV. Both DFIT injection and closure processes are numerically modeled - and depending on which model parameters we choose to fix and which we perturb, we can preemptively estimate the potential for a successful stimulation and its possible dimensions.
This estimate can be obtained at the early stages of a field /section development, before embarking on major drilling and completion campaigns, even in the absence of substantial production data. And it provides guidance for optimizing major fracturing design and well spacing.
This approach is not reliant or bound by the assumptions underlying widely-used analytical DFIT analyzing methods, and is therefore more flexible and better captures the physics of stimulation in unconventional reservoirs. An early understanding of the key geomechanical metrics defining unconventional reservoir enhancement (DSRV effectiveness) allows us to build a directional relationship between fracturing parameters and post-fracture production without the need for an extended record of production trends. This speeds up the continuous learning and adaptive process of completion optimization involving pumped volumes, cluster spacing and well landing zones.
Case Study of a Landing Location Optimization within a Depleted Stacked Reservoir in the Midland Basin
Authors: Defeu Cyrille , Williams Ryan , Shan Dan , Martin Joel , Cannon Dave , Clifton Kyle , Lollar Chad 
Published: January 2019

Abstract
Unconventional plays across the US are often made of stacked pays, typically ranging from a few hundred to thousands of feet thick. These stacked pay intervals are generally segregated into different formations as dictated by differences in geology, mineralogy, rock fabric, and fluid type. This proves to be a challenge because many stacked/staggered horizontal wells are required to provide effective coverage of the reservoir. Selecting the right landing location can become even more challenging in an environment with existing producing wells in adjacent formations because pressure depletion and its associated effects on fracture propagation necessitate consideration of vertical spacing and time.
In this study, we outline an integrated approach that addresses a four-dimensional horizontal well placement challenge in the Midland basin's Wolfcamp A formation using advanced hydraulic fracture modeling to calibrate hydraulic fracture geometries and history match five producing wells in both Lower Spraberry and Wolfcamp B.
The optimal landing location within the Wolfcamp A was determined based on an assessment of reservoir quality, rock mechanics, unique structural features, and depletion effects. These data were then combined to form a 4D geomodel that enabled a completion optimization study via modeling of the resulting complex hydraulic fracture geometry and subsequent hydrocarbon production.
This integrated workflow, using a wide array of high-quality datasets and the input of experts from multiple disciplines, yielded a comprehensive assessment and clear recommendations for this challenging partially depleted stacked pay interval. Although this study is specific to the Midland basin's Lower Spraberry and Wolfcamp A and B formations, many sections of the workflow apply to other basins and their unique strata.
Child Well Analysis from Poroelastic Pressure Responses on Parent Wells in the Eagle Ford
Authors: Das Paloma , Solaja Ola , Cabrera Julio , Scofield Reid , Coenen Erica , Kashikar Sudhendu , Kahn Charles 
Published: January 2019

Abstract
The industry continues to face a challenge understanding and optimizing completion strategies to minimize the impact of infill development on existing wells and achieve larger Stimulated Reservoir Volume (SRV) on infill wells. This paper presents a cost-effective technique for evaluating parent-child interaction using poroelastic pressure responses on the parent wells. The method was employed on a four-well pad in the Eagle Ford to understand diversion effectiveness and the extent of offset depletion.
The case study comprised the analysis of pressure data sets, covering wellhead pressure data from the nearby parent wells. The method quantifies and interprets pressure signal magnitude and its transient behavior for each completed stage. The well offsetting the parent well was completed using two different completion designs. One half of the lateral was completed without employing diversion, while the other half employed a specific diversion strategy. The primary goal of the case study was to demarcate the areal extent and degree of depletion around the existing wells and determine the effectiveness of using diversion in inhibiting growth towards parent wells.
The analysis determined fluid and fracture pathways, mainly seen driven by formation stresses, depletion, and completion design in each stage. The case study compared the effects of employing diversion vs. not employing diversion, using the magnitude of pressure responses felt by the parent well. The initiation points of the pressure signals, as felt by the offset wells on each side quantified how quickly and in which direction the newly treated fractures were growing. The pressure responses from multiple parent wells were correlated to understand the areal extent of depletion around each offset producer. This ultimately promotes understanding the difference in pre and post production of the wells and optimizes infill completions for future development.
Cross well analysis using poroelastic pressure responses is easy to implement and very cost-effective. The proposed method provides a workflow to analyze offset pressure data in a consistent and reproducible manner. This method affords the industry a better understanding of parent well damage and mitigation of child well productivity loss.