bluuebunny/crossref_metadata_2025 huggingface dataset:
Bridging Criteria and Distribution Correlation for Proppant Transport in Primary and Secondary Fracture
Authors: Kou Rui , Moridis George , Blasingame Thomas
Published: January 2019

Several recent studies have reported that proppant "bridging" (blocking) occurs at the interface between primary and secondary fractures. Such bridging blocks flow and significantly reduces the efficiency of proppant placement. The prevention of bridging is of great importance, but the criteria for bridging formation have yet to be determined. In this numerical study of proppant transport, we propose bridging formation criteria and analyze the associated distribution correlations that quantify the amount of proppant that migrates into the secondary fractures.

To model the complex interactions between proppant particles, fracturing fluids, and fracture walls, we use the discrete element method (DEM) coupled with computational fluid dynamics (CFD). We calibrate our model using widely accepted bed-load transport measurements. The simulation domain involves a "T-type" intersection of primary and secondary fractures. We investigate the effects of various proppant sizes and concentrations on bridging formation. In all cases, we investigate the occurrence of bridging and we quantify its impact by estimating the corresponding percentage of proppant reaching the secondary fractures.

Our simulation results show that the efficiency of proppant placement in the secondary fractures depends on the flow regime. In the suspension regime, proppant particles can be easily mobilized by the fluid drag force. This leads to a relative high proppant placement efficiency in the secondary fractures. When proppants are in the bed-load transport regime, kinetic energy transferred from the fluid drag force is dissipated by inter-particle collisions and the friction force. In this case, the amount of proppants entering the secondary fractures and the distance that proppants can cover are restricted compared to the case of proppants associated with suspension transport.

Our investigation reveals that two parameters are critical for the occurrence of proppant bridging (blocking) at the secondary fracture interface. These parameters are — the proppant concentration Cp and the ratio between the secondary fracture aperture and the proppant diameter (Rfp). At a fixed value of Rfp, continuous transport of proppant can be achieved when Cp is lower than a threshold value. Based on this finding, we use Rfp and Cp to propose a blocking criterion correlation.
Generation of In-Situ Proppant through Hydro-Thermal Reactions
Authors: Tong Songyang , Miller Chammi , Mohanty Kishore
Published: January 2019

During hydraulic fracturing treatments, proppants often settle near-wellbore in low viscosity fracturing fluids (e.g., slick water) and leave a large fractured surface unpropped. Poor placement of proppant could lead to a loss of fracture conductivity and undermine the productivity of shale wells. In addition, lots of microfractures are too narrow to accommodate commercial proppants and would close during production. In this study, a hydro-thermal reaction is proposed to generate hydroxyapatite crystals on calcite-rich shale surface to act as in-situ proppants to improve fracture conductivity. First, batch experiments were conducted in both low salinity frac water and seawater brine. Crystals were generated in both low and high salinity (and hard) brines. The crystals grew to several hundred microns and tended to form along calcite-rich layers, according to SEM image analysis. The hardness data showed that properly designed formulations could avoid the shale softening effect. Second, reactive flow experiments were performed to evaluate fracture conductivity change after chemical treatment. A typical 3-10 times increase in post fracture conductivity was observed for both reservoir and outcrop shale samples.
Integrated Analysis of the Coupling Between Geomechanics and Operational Parameters to Optimize Hydraulic Fracture Propagation and Proppant Distribution
Authors: Singh Ankush , Xu Shaochuan , Zoback Mark , McClure Mark
Published: January 2019

This paper presents an analysis of the interactions between stimulation design and two important geomechanical effects: the variation of least principal stress (Shmin) between lithological layers and the stress shadow effect that arises from simultaneously propagating adjacent hydraulic fractures. To demonstrate these interactions, hydraulic fracture propagation is modeled with a 5-layer geomechanical model representing an actual case study. The model consists of a profile of Shmin measurements made within, below and above the producing interval. The stress variations between layers leads to an overall upward fracture propagation and proppant largely above the producing interval. This is due to interactions between the pressure distribution within the fracture and the stress contrast in the multiple layers. A sensitivity study is done to investigate the complex 3-D couplings between geomechanical constraints and well completion design parameters such as landing zone, cluster spacing, perforation diameter, flow rate and proppant concentration. The simulation results demonstrate the importance of a well characterized stress stratigraphy for prediction of hydraulic fracture characteristics and optimization of operational parameters.
The World's First Offshore Multilateral Well Completed with Multistage Proppant Fracturing: A Case Study from Offshore Black Sea
Authors: Tomlins Andrew , Conrad Joel , Bocaneala Bogdan
Published: January 2019

The paper aims to present the successful execution of the first offshore multilateral well completed for multistage high-pressure proppant stimulation - in the Black Sea, offshore Romania. The paper describes the drivers that lead the operator to trial a multilateral well as well as cover the considerations made in selecting, defining and executing the final completion solution with a review of the lessons learned.

With only one platform slot left and a significant undrained area of reservoir the operator had to maximise the hydrocarbon recovery through a single well which, due to pressure to increase the operator's daily production, had to be finalised in just one year. Building on field experience gained since 2008 in drilling and completing for multistage proppant stimulation a detailed screening and evaluation of multilateral completion technologies was performed. The focus was on developing a concept that would minimise risks during execution while meeting cost and lead time objectives, which necessitated customising the chosen TAML Level 3 completion design and installation methodology.

To maximise rig-time efficiency the well was executed in two phases: 1) drilling and lower completion installation of both branches with a drilling rig and 2) stimulation and upper completion installation with the platform's workover rig. With six stages in each lateral the high-pressure stimulation was executed by a converted supply vessel in four sailings, necessary to reload materials. To meet the delivery schedule, ensure simplicity and utilise operator experience the completion was realised with no dedicated multilateral hardware, rather, through the effective use of standard multistage stimulation open hole completion equipment and appropriately engineered bent joints to exit the main bore.

With initial production rates higher than anticipated, the multilateral well completed in this manner has proven to be considerably more economic than drilling two horizontal wells with equivalent reservoir coverage. The success of this well serves as a proof of concept and provides increased confidence in delivering reliable, cost effective multilateral wells even under tight time constraints and in areas and/or operators with no history of multilateral well completions
Barriers to Hydraulic Fracture Height Growth: A New Model for Sliding Interfaces
Authors: Xu Wenyue , Prioul Romain , Berard Thomas , Weng Xiaowei , Kresse Olga
Published: January 2019

This work introduces a new set of energy-balance-based criteria for the vertical growth of a plain-strain planar hydraulic fracture across a horizontally laminated reservoir formation with heterogenous layer properties and multiple weak interfaces. Combined with Coulomb's friction law for mechanical balance along sliding interfaces, these criteria were built into a novel semi-analytical model of fractional fracture height growth. The model was then applied to investigate the growth of hydraulic fractures in an idealized symmetric three-layer rock formation, with the upper and lower layers acting as barriers to the growth. Preliminary modeling results show how the vertical growth of a hydraulic fracture is influenced by the various mechanical/energy barriers. Three primary types of barrier behaviors are identified. A stress barrier leads to gradually increasing fluid pressure when the barrier layer is crossed. A toughness/modulus barrier, on the other hand, results in an immediate sharp increase in fluid pressure followed by gradual decline in pressure. The effect of individual sliding interfaces is similar to that of a toughness/modulus barrier. The cumulative effect becomes more important when multiple closely spaced interfaces are present. A formation layer containing multiple closely spaced weak interfaces behaves collectively much like a stress barrier.
Determining the Most Effective Diversion Strategy Using Pressure Based Fracture Maps : A Meramec STACK Case Study
Authors: Kopp Jeff , Kahn Charles , Allen Charlee , Huchton Jake , Robinson Clark , Coenen Erica
Published: January 2019

This paper discusses a STACK (Sooner Trend Anadarko Basin Canadian and Kingfisher Counties) case study that determined the effectiveness of different diversion techniques, including pods, sand ramps with sand slugs, rate cycling, and utilization of the completions order to control fracture growth. A secondary goal of this study was to evaluate the suitability of pressure-based fracture maps and oil and water phase tracers in monitoring diverter effectiveness.

Effectiveness of a given diverter technique and diverter drop was evaluated using the two techniques on a 3-well pad. The three wells were completed using a combination of: 4 pods per treatment interval6 pods per treatment interval8 pods per treatment intervalhigh-volume proppant loading per treatment interval

The effectiveness of the diverter drop was evaluated using each of the diagnostic techniques listed above. The pressure-based fracture analysis uses the pressure response recorded in an isolated stage in the monitor well to compute fracture geometry and the rate of growth of the fracture dimensions. The effectiveness of a given diverter drop is classified into one of four possible categories: stop dominant fracture growth, impede dominant fracture growth, no impact on growth of dominant fracture and accelerate the growth of dominant farcture. These results were then compared with the analysis from oil and water phase tracers and treatment pressure analysis.

Successful (effective) diversion was observed on 82 % of the stages with pods compared to 64% successful diversion where sand ramps were used. In addition, stages using 8 pods for diversion had a 15% reduction in average fracture half-length compared to stages using 4 pods. Fracture height was better controlled through the order of completions of the stages between 3 wells. Completing the middle well in the upper part of the zone ahead of the two outer wells in the lower part of the zone, controlled the vertical height growth of the two outer wells.

The offset pressure-based analysis proved to be as effective in accurately diagnosing the diverter effectiveness and provided a significant cost and timing advantage compared to other diagnostic techniques.
Three-Dimensional Analysis of Interactions Between Hydraulic and Natural Fractures
Authors: Daneshy Ali
Published: January 2019

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

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

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

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

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

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

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

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

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.
The Limits of Fluid Flow in Propped Fractures- the Disparity Between Effective Flowing and Created Fracture Lengths
Authors: Barree R.D. , Duenckel R.J. , Hlidek B.T.
Published: January 2019

Post hydraulic fracture diagnostics often leads to an estimation of effective fracture lengths that are substantially shorter that the created length. (Ibrahim et al. 2017, Barree et al. 2003) This gives rise to questioning validity of the diagnostics or concerns regarding execution of the fracture stimulation itself. The objective of the paper is to show that short effective lengths are understood and predictable in the context of the physics of flow in propped fractures. Extensive laboratory testing of a broad range of proppants under a wide range of conditions has led to a databased and detailed understanding of pressure drop in a propped fracture as a function of fluid flow. The pressure drop in turn will dictate inflow from the reservoir at any point along the fracture. This interaction of pressure drop in the fracture and reservoir inflow will in turn dictate the flowing length of the fracture. Testing has demonstrated and it is well understood that the conductivity of a proppant under downhole conditions in a propped fracture is significantly less than that measured in the lab under ideal conditions of single phase Darcy flow at 2 lbm/ft2 loading. (Duenckel et al. 2017) This results from the combined effects of low proppant concentrations, frac fluid damage, multiphase flow and non-Darcy flow as well as other damage mechanisms. The paper will demonstrate that the pressure loss in the fracture resulting from the combined effects of these damage mechanisms quickly consumes the available energy to the point that the viscous forces are less than the capillary and gravity forces in the fracture, limiting further flowing length. In very low permeability reservoirs inflow from the reservoir quickly becomes insufficient to overcome gravity and capillary forces. The paper will also address the following question: if effective lengths are very short of what benefit is pumping large volumes of proppant? Further, how does one explain apparent field evidence for long fracture lengths (e.g. pressure communication) if indeed the effective length is much shorter? The paper will show how effective fracture lengths are not dependent on propped fracture properties alone. Given the limited effective conductivity resulting from a combination of damage mechanisms, the interaction of the propped fracture conductivity and reservoir inflow dictate effective fracture lengths. The resulting effective lengths are expected to be much shorter than the created lengths.
Improving Hydraulic Fracturing Performance and Interpreting Fracture Geometry Based on Drilling Measurements
Authors: Downie Robert , Daves Dusty
Published: January 2019

It is a well-established principle that rock properties affect fracture geometry. This paper investigates the relationships between fracture responses observed during completion operations and rock properties that are obtained during the drilling of a well. It will also attempt to quantify the benefits of designing completions based on these rock properties.

Four pairs of wells adjacent to one another are included the study. Each pair of wells includes one well with a completion design based on the operator's baseline guidelines, and one well with the perforation depths and stage boundaries selected from rock strength information derived from drilling data. The fracture treatment pressure responses are correlated to the rock properties, and the two completion methodologies are compared to determine whether there is an operational or production benefit to this completion methodology.

The results of the study show a clear and distinctive difference between treatment responses in wells whose completions are based upon drilling-derived rock properties, and those that did not. The most striking of these differences is that instantaneous shut-in pressures were higher in wells where completion stages and perforation depths were selected based on rock properties, without corresponding increases in average treatment pressures. This is likely an indication of improved fracture containment (higher net pressures) which would be expected with an equitable fluid distribution among perforation clusters. Further to this, the analysis allowed for the identification of rock parameters associated with increased risk of excessive height growth which is independent of the completion methodology used. Production comparisons will be included to support the findings.

The result of this work is a clear path forward to improving future wells by understanding how rock properties and completion design are related to fracture height growth. This allows for a re-evaluation of future drilling targets and the modification of treatment designs to maintain the maximum amount of fracture energy within the target zone. It will also help to provide further evidence that completions can be improved through the optimized placements of stage boundaries and perforation clusters.

This paper will present a new analytical workflow that combines the use of drilling-derived rock properties and fracture treatment responses to gain important insights and drive future decisions for both the drilling and completion processes.
Apparent Toughness Anisotropy Induced by Roughness of in Situ Stress: A Mechanism that Hinders Vertical Growth of Hydraulic Fractures and Its Simplified Modeling
Authors: Fu Pengcheng , Huang Jixiang , Settgast Randolph R. , Morris Joseph P. , Ryerson Frederick J.
Published: January 2019

A hydraulic fracture's height growth is known to be affected by many factors that are related to the layered structure of sedimentary rocks. While these factors are often used to qualitatively explain why hydraulic fractures usually have well-bounded height growth, most of them cannot be directly and quantitatively characterized for a given reservoir to enable a priori prediction of fracture height growth. In this work, we study the role of the "roughness" of in situ stress profiles, namely alternating low- and high-stress among rock layers, in determining the tendency of a hydraulic fracture to propagate horizontally versus vertically. We found that a hydraulic fracture propagates horizontally in low-stress layers ahead of neighboring high-stress layers. Under such a configuration, a fracture mechanics principle dictates that the net pressure required for horizontal growth of high-stress layers within the current fracture height is significantly lower than that required for additional vertical growth across rock layers. Without explicit consideration of the rough stress profile, the system behaves as if the rock is tougher against vertical propagation than it is against horizontal fracture propagation. We developed a simple relationship between the apparent differential rock toughness and characteristics of the stress roughness that induce equivalent overall fracture shapes. This relationship enables existing hydraulic fracture models to represent the effects of rough in situ stress on fracture growth without directly representing the fine-resolution rough stress profiles.
Empirical Links Between Sub-Surface Drivers and Engineering Levers for Hydraulic Fracture Treatments and the Implications for Well Performance
Authors: Stephenson Ben , Bai Taixu , Huckabee Paul , Tolle John , Li Ruijian , MacDonald Jeff , Acosta Luis
Published: January 2019

Does the sub-surface drive completion design or is the rock less of a concern with industry trends to higher proppant-, fluid- and stage-intensities? To address this challenge it was first necessary to understand; 1) how the sub-surface could potentially influence completion and stimulation design, 2) what are the available engineering levers and moreover, 3) whether well performance has actually been impacted by tailoring completions in different plays from specific case-studies.

Although there is a multitude of published field examples of how completion design changes have driven value, clarity around the inter-connectedness with sub-surface variability, either between plays or within a play, is commonly missing. New templates have been developed that describe the conceptual links between the nine key 'Sub-surface Drivers' for hydraulic fracturing and their associated engineering Levers categorized by well-, fluid-, proppant- and stage-design. These templates are a compilation of extensive empirical observations from both operations and field performance reviews incorporating thousands of wells across North America, supported with learnings from geomechanical theory and modeling.

The nine Sub-surface Drivers that influence completion design and control the access to hydrocarbons are, 1) mobility, 2) reservoir pressure, 3) gross thickness, 4) layering heterogeneity, 5) rock stiffness, 6) natural fractures, 7) stress anisotropy, 8) risk of fraccing faults and, 9) risk of fraccing out of zone. Drivers 1-7 govern the connectivity, whereas 8 and 9 influence stimulation ineffectiveness. It is proposed that there are approximately fifteen primary engineering Levers related to these nine Drivers, which have been shown to have a measurable impact on completion effectiveness and/or production.

Case studies illustrate that the Sub-surface Drivers play a significant role in most plays, but they are not all relevant in every play. The challenge is to acknowledge the variability, or lack of, and pursue completion design optimization goals, while managing the variance in the well performance range.

Whereas industry trends of increasing completions intensity have delivered more value in many plays, the Sub-surface Drivers concept have primarily proven useful to mitigate against poor wells in development and explain exploration failures. By developing a systematic set of templates for Drivers and their respective levers, learnings from other operators can be high-graded through the formulation of connectivity analogues with the goal of showing where changes in completion design may be more, or less applicable.
Nine Plus Years of Production Show Value of Proper Design in Oil Window of Barnett Shale
Authors: Ely John W. , Harper Jon , Nieto Esteban N. , Kousparis Dimitrios , Kousparis Andrew , Crumrine Curt
Published: January 2019

The Northern extension of the "COMBO" Barnett Shale is located primarily in Montague, Cooke, and Clay counties in the North Texas region. This play is unique in that the shale in the area is very rich in total organic content (TOC) and contains a relatively high concentration of carbonates throughout. This extension is primarily inside the the oil window of the Barnett, rather than predominately within the more gas-rich region, which dominates the rest of the shale's development throughout North Texas (See Figure 1). Some of the earliest technological enhancements in oil production from shale occurred in the COMBO Barnett play, prior to the expanse and relative boom of the Eagle ford shale, and many other successful unconventional oil shale plays throughout the industry, both domestic and international. The Barnett in this area is typically quite thick, with sections from 300-700 feet. In some cases, naturally occurring fractures are fairly evident and can be identified through the use of image logging, prior to the completion phase of a well. Some areas may exhibit limited natural fractures, but have very brittle rock. Vertical completions were dominate during the early development of the Barnett, constituting a vast majority of oil and gas wells in production within the region. In fact, measureable time in production for the wells in the area indicated that properly completed vertical wells had respectable economics, which were later, at times, enhanced with horizontal drilling and multi-stage frac completions and re-completions.
Simplification and Simulation of Fracture Network Using Fast Marching Method and Spectral Clustering for Embedded Discrete Fracture Model
Authors: Xue Xu , Rey Alvaro , Muron Pierre , Dufour Gaelle , Wen Xian-Huan
Published: January 2019

Embedded Discrete-Fracture Model (EDFM) is designed to accurately represent realistic hydraulic fracture network (HFN) and provide efficient performance predictions by honoring the fracture topology. Due to the complexity of HFN, the EDFM grid may be computationally inefficient, particularly for field-scale applications with millions of fracture cells. This paper aims at incorporating the Fast Marching Method (FMM) and spectral clustering for fast HFN analysis, simplification and simulation under the framework of EDFM.

HFNs are first generated using a commercial hydraulic fracture simulator. The FMM is used to solve the pressure front propagation using the fracture graph and subsequently the ‘diffusive time of flight’, well and completion index are calculated. The results are used as pre-conditions to split the fracture graph into connected components, which are subsequently partitioned using spectral clustering. The resulting clusters are used for fracture simplification resulting in a significantly lower number of fracture elements for flow simulation. To demonstrate the feasibility of the workflow, we use the Multi-Well Pad pilot model, which is characterized by a complex HFN and a high-resolution matrix system. We investigate the relationship between matrix resolution (characterized by the matrix-fracture size of the reservoir cells) and the ratio of oil and gas production on the field. Our investigation provides an alternative approach to explain the very large Gas Oil Ratio (GOR) reported for this type of reservoirs. The required levels of refinement to correctly represent the observed GOR presents an opportunity to test the efficiency and accuracy of our proposed workflow for HFN simplification. We use the results of the FMM applied to the high-resolution models to find an optimal spectral fracture clustering. The results show that the proposed workflow can achieve massive fracture cells aggregation (with only 1% of the original fracture cell number) while maintaining the accuracy.

This is the first study for analysis, simplification, and simulation of HFN for EDFM using a field scale model. The main contributions are: (i) honor the topology of complex HFNs in EDFM and is able to represent the complex physics observed in the oil and gas shale reservoirs, (ii) HFNs diagnosis without simulation, and (iii) massive fracture aggregation with an error below 5 percent, and speed-up higher than 16 times of the fine scale model.