bluuebunny/crossref_metadata_2025_split huggingface dataset:
Impacts of Diverse Fluvial Depositional Environments on Hydraulic Fracture Growth in Tight Gas Reservoirs
Authors: Cuba Patricia H. , Miskimins Jennifer L. , Anderson Donna S. , Carr Mary M. 
Published: January 2011

Abstract
In an attempt to enhance the understanding of fracture growth in fluvial systems, this paper provides an analysis of the impact of depositional environments and associated heterogeneities on hydraulic fracturing growth in fluvial tight gas reservoirs. A 3D geostatistical reservoir model, representing a 160-acre field area, was created based on a 3D meandering fluvial tight gas geologic model developed from outcrop. This detailed geologic model differentiates between sandstone-dominated channel- belt environments including point bars, crevasse channels, and crevasse splays as well as the intervening overbank environments consisting of mudstone and coal deposits. Petrophysical properties and reservoir conditions, used in the reservoir model, were based on subsurface data from nearby producing fields with comparable fluvial systems.
Two different well locations were then chosen within the 3D model in an effort to capture various sandstone body distributions. A range of hydraulic fracture orientation planes, associated with the two well locations, were chosen and loaded into a 3D hydraulic fracture modeling package. Various stimulation treatment sensitivities, representing eight cases, were performed.
Results show that consideration of both vertical and lateral reservoir changes is critical to understanding fracture growth in fluvial systems. When comparing a layered system, with no lateral variation, to a system with lateral variation, one-year cumulative production can be different by ~9%. Subtle lithofacies variations, present in significant quantities in these complex depositional systems, can have a large effect on fracture growth. Additionally, how depletion is treated in the fracturing model, i.e. whether the entire interval is considered depleted or just a singular sand body, can also have a significant effect on fracture propagation.
Parameters Effecting the Interaction among Closely Spaced Hydraulic Fractures
Authors: Bunger A. P. , Zhang X. , Jeffrey R. G. 
Published: January 2011

Abstract
Placing multiple hydraulic fractures at intervals along horizontal wells has proven to be a highly effective method for stimulation. However, the mechanical interaction between a growing hydraulic fracture and one or more previous hydraulic fractures can affect the fracture geometry such that the final fracture array is suboptimal for stimulation. If the fracture array geometry is idealized as a set of regular and planar fractures, history matching and production forecasting may be inaccurate. During the treatments, the fractures can curve towards or away from one another, potentially intersecting one another. A detailed parametric study of this phenomenon using a coupled 2D numerical fracturing simulator shows that the curving is associated with a combination of opening and sliding along the previously placed hydraulic fracture, as well as the previous fracture’s disturbance of the local stress field because of its propped width. Dimensional analysis and scaling techniques are used to identify the key parameters that are associated with suppression of each mechanism that can lead to hydraulic fracture curving. The analysis, which is in agreement with available data, results in a clarification of the conditions under which attractive and repulsive curving are expected, as well as the conditions under which curving is expected to be negligible or even completely suppressed. This last case of planar hydraulic fracture growth is of practical importance and will usually be considered desirable. We present a straightforward method for determining whether planar fracture growth is expected that additionally gives insight into how design parameters can be modified to promote planar hydraulic fracture growth.
Hydraulic Fracture Propagation in Pre-Fractured Natural Rocks
Authors: Meng Chunfang , de Pater J. 
Published: January 2011

Abstract
We conducted a series of hydraulic fracture initiation tests with fractured natural rock samples. The objective is to characterize the interaction between hydraulic fracture initiation and natural fracture infiltration and opening. The natural fracture was simulated by cleaving a rock cube into two or three layers and putting the parts back together. The hydraulic fracture is initiated by pressurizing the borehole drilled perpendicular to the layers. The test parameters include rock type (sandstones and a tight limestone), confining stress and fluid type (silicon oil and cross-linked gel). A detailed model was built to simulate the hydraulic fracture interaction with a natural fracture. Qualitative agreement was found with the test results.
Interpretation of Wellbore Temperatures Measured using Distributed Temperature Sensors during Hydraulic Fracturing
Authors: Hoang Hai , Mahadevan Jagannathan , Lopez Henry 
Published: January 2011

Abstract
Tight gas plays often have multiple lenses of producing formations. Limited entry completions became the most cost effective method to complete and produce tight gas wells in these layered reservoirs. The rate and volume of fracturing fluid injected into the different layers has an important role in determining the fracture characteristics. However, due to the restriction of down-hole equipments, it is very challenging to obtain specific injection rate for each perforated zone. Temperature variations in the well bore, outside the casing, are available using new technology such as distributed temperature sensor (DTS) fiber optic cables. The main objective of this study is to relate the well bore temperature changes as measured by DTS data to the wellbore and fractured interval injection rates during a multizone fracturing process.
We develop a forward simulation model, based on mass and energy conservation, for calculating the temperature profile and temperature history in the wellbore and in the rock surrounding the wellbore. The model allows for liquid flow into the fractured interval. Subsequently, the model is integrated with an inverse estimation algorithm which is used to estimate flow rates both in the wellbore and into the fractured interval. The estimation algorithm is based on a gradient search method.
Our estimation results show a good comparison of the temperature profiles with that observed in the field by using DTS. Also, the model is able to estimate a flow rate history consistent with total field injection volume. This work enables an accurate and quick interpretation of the wellbore DTS data to determine the interval injection rates during a hydraulic fracturing process. Knowledge of accurate interval injection rates and the corresponding fracture characteristics can be useful in designing better limited entry completion that can optimize the fracture length using rate control.
Characterizing Dynamic Fracture Growth and Azimuth using Seismic Moment Tensor Inversion Analysis of Microseismicity
Authors: Mace Kaitlyn , Urbancic Ted , Baig Adam 
Published: January 2011

Abstract
Based on traditional fracture models it is generally considered that fractures develop along a single fracture azimuth or along a plane of fracturing controlled by regional stresses (along the maximum principle stress direction), even within the context of a three-dimensional fracture network. Recently, the utilization of distributed geophone arrays around treatments has provided for an opportunity to investigate the way these fractures develop by examining the microseismic events recorded during a stimulation, utilizing a Seismic Moment Tensor Inversion (SMTI) approach.
SMTI provides additional information on the events beyond location and magnitude, such as the relative contribution of isotropic versus shearing components of failure, the potential fracturing plane orientations and the localized strain axes responsible for the failures. Additionally, SMTI data can be further used in Deformation State Analysis (DSA) to define the stress-strain field responsible for the growth and development of the hydraulic fracture.
In this study, we examined microseismicty associated with an open-hole completion program in a tight sand formation in North America. We observed that the DSA-derived localized stress-strain field was perturbed by the stimulation program, being highly variable both spatially and temporally. The results further suggest that fractures progress in a complex system of both macro- and micro-fractures containing several different azimuths, with progressive growth occurring as a result of stress shedding to adjacent fractures or zones of weakness. This localized fracturing behavior led to the development of an interconnected fracture network, which resulted in hydraulic fracture growth in the direction of the regional maximum horizontal shear stress.
A Unique, Large-Scale Computer Tomography Scanner: Investigation of Fracture Cleanup with Different Materials
Authors: Cheremisin Alexey N. , Zinchenko Alexey , Lecerf Bruno , Pavlova Svetlana , Thompson Karsten E. , Lane Nathan 
Published: January 2011

Hydraulic fracturing is a widely used technique for production enhancement. One critical property of a hydraulic fracture is the fracture conductivity, which has a direct impact on the productivity and hence, the economics of the stimulated well. Several laboratory techniques have been developed to characterize the materials that are placed in the fracture and influence its conductivity. Conductivity laboratory measurements have become a routine experiment with well-established procedures and setups aimed at simulating downhole conditions. However, correlating the performance of materials in a conventional laboratory setup with their performance in real conditions is not straightforward. This problem occurs because conventional laboratory setups are of limited length scale and fail to capture processes and variations that occur at a scale of the order of, or exceeding, the dimensions of the conductivity cell. Also, even if conventional setups provide accurate and reproducible measurements, they fail to provide fundamental, in-depth understanding of the actual processes that occur at the pore scale, occur in the fracture, and influence the fracture conductivity.
A unique, large-scale X-ray computer tomography (CT) setup improves understanding of the factors influencing fracture conductivity. The state-of-the-art setup allows taking high-resolution scans of a proppant pack under conditions similar to an actual fracture. The setup provides unique insight into static and dynamic phenomena occurring at the proppant and the pore scale. The use of imaging software then provides an accurate 3D image over the entire length of the proppant pack. Computer models of flow in porous media can then be used to predict the flow and its parameters in the propped fracture and its porous network specified by the high-resolution images. Moreover, the setup scale (1 m long) is much larger than that of a conventional conductivity cell (20 cm long). The larger dimensions are adequate to capture heterogeneous processes such as fracture cleanup.
The performance of the new setup was validated using baseline proppant pack conductivity and non-Darcy flow coefficients experiments. An example was also shown where the unique X-ray CT setup was used for investigating fracture cleanup of new, elongated rod-shaped nondeformable high-strength proppant compared with conventional spherical proppant. The CT images show how the new proppant provides a better fracture cleanup compared with spherical proppant. For both cases, images showing the distribution of residual gel saturation highlight how pore volume geometry affects fracture cleanup.
Enhanced Reservoir Characterization Using Hydraulic Fracture Microseismicity
Authors: Maxwell S. C. , Cho D. , Pope T. , Jones M. , Cipolla C. , Mack M. , Henery F. , Norton M. , Leonard J. 
Published: January 2011

Abstract
Microseismic measurements were integrated with seismic reservoir characterization and injection data to investigate variability in the hydraulic fracture response between three horizontal wells in the Montney shale in NE British Columbia, Canada. When wells were close enough, hydraulic fractures were found to interact with pre-existing faults, which acted as a barrier to fracture growth, and resulted in relatively large-magnitude microseismicity. Pre-existing faults were identified by edge detection/ant tracking algorithms applied to seismic reflection data, as well as from advanced analysis of the microseismicity, including microseismic deformation levels, magnitude-frequency characteristics and composite failure mechanism analysis. In cases where the wells were far from pre-existing faults simple, planar hydraulic fractures were observed, although there was a tendency to grow towards regions of low Poisson’s ratio based on amplitude versus offset inversion of the seismic reflection data. The tendency for the hydraulic fractures to be asymmetric and grow preferentially towards the low Poisson’s ratio region is attributed to material property changes and associated lower stresses in these regions. Insight from the enhanced reservoir characterization with integrated microseismic and treatment data is being used for better well placement, improved completion designs and increased production.
Marcellus Shale Hydraulic Fracturing and Optimal Well Spacing To Maximize Recovery And Control Costs
Authors: Edwards Krisanne L. , Weissert Sean , Jackson Joshua , Marcotte Donna 
Published: January 2011

Abstract
EQT wants to maximize recovery and control development costs in its Marcellus shale development program, which consists of multi-stage fractured horizontal wells. To achieve this objective the asset team considered tighter well spacing. But at what distance do fracture-stimulated wells directly interact? Microseismic data implies that the radius of influence is greater than 1,000 ft. However, after 6 months of production, a study using a nodal analysis software model suggests an effective frac half-length less than half of this, a finding that has been supported in other EQT wells across Pennsylvania and West Virginia.
To test this concept for horizontal wells with multi-stage slickwater, sand-propped frac completions in the Marcellus shale—where well spacing is typically 1000-1200 ft—well spacing was reduced to just 500 ft, in three different areas of the Marcellus. The goal was to better understand: How do the hydraulic fractures interact? Are the closer spaced wells more likely to share reserves? Does the frac design need to be adjusted for tighter spaced wells?
To answer these questions, 500-ft and 1000-ft offset wells were monitored during completion with microseismic, radioactive tracers, chemical tracers, and pressure gauges. Production logging was initially scheduled to begin 4-6 months after production, however, had to be postponed.
With more than 6 months of production data in the first of the three development areas, the 500-ft-spaced wells and 1000- ft-spaced wells are performing similarly, despite frac communication during the completion of the 500-ft wells. Estimates of effective frac half-length from the nodal analysis model support this conclusion.
A unique, comprehensive data set is collected across the Marcellus shale to document how hydraulic fracturing influences well performance, and the study attempts to reconcile conflicting frac half-length interpretations to identify optimal well spacing. The results to date support tighter spacing, which maximizes recovery and facilitates multiple wells to be drilledfrom the same pad, thereby minimizing the footprint for "greener" operations.
An Alternative Interpretation of Microseismic Events during Hydraulic Fracturing
Authors: Dahi Taleghani Arash , Lorenzo Juan M. 
Published: January 2011

Abstract
It is common practice in industry to monitor hydraulic fracturing jobs by picking major, micro-earthquake events in seismograms whose source locations form a spatial pattern used for interpreting induced fractures. Surprisingly, controversy still surrounds the interpretation of these scattered, discrete events. Many authors conclude that hydraulic fractures are generated by shear failure events rather than tensile failures. This interpretation contradicts our common understanding of fracture mechanics, which describes the hydraulic fracture process as taking place predominantly in mode-I failure (pure tension). We propose that band-width limited instrumentation during seismic field recording may be partly to blame. Low-frequency (&lt;;5 Hz) tensile-source events which are expected to occur continuously between shear events are largely ignored. Herein, we try to compare the total energy of detected shear events with the total energy of expected low-frequency tensile events in the background in order to justify the main (tensile) mechanism of fracturing. Major, shear-mechanism events may not describe accurately the temporal and spatial pattern of induced fractures in the subsurface. Shear events may only represent the locations where hydraulic fractures intersect pre-existing discontinuities. Therefore, by only considering shear events, we may not be able to make a correct estimation of the orientation and extension of the hydraulic fractures. We suggest that only by recording silent (low frequency) events, we will truly be able to describe induced subsurface fracture geometries.
Simulating Hydraulic Fracturing in Real Fractured Rocks - Overcjavascript:iterm()oming the Limits of Pseudo3D Models
Authors: Nagel Neal , Gil Ivan , Sanchez-nagel Marisela , Damjanac Branko 
Published: January 2011

Abstract
With the huge growth in the stimulation of naturally fractured formations, it is clear that the industry needs new hydraulic fracturing simulation tools beyond the limits imposed by pseudo3D fracturing model. Discrete element models (DEM), in which both matrix block behavior and fracture behavior are explicitly modeled, offer one option for the specific modeling of hydraulic fracture creation and growth in naturally fractured formation without, for example, the assumption of bi-planar fracture growth.
In this paper, we show the results of the successful realistic simulations of fluid injection into a given NFR using the 3DEC DEM model. The simulations included coupled fluid flow-deformation analysis, failure type and extent calculations, as well as a series of parametric analyses. The parameters investigated included: 1) injection rate and its effect on the overall injection results, and 2) fluid viscosity, which had a significant influence on the ratio of tensile (mode 1) failure versus shear failure.
Challenges of Designing Multi-Stage Frac Packs in the Lower Tertiary Formation - Cascade and Chinook Fields
Authors: Haddad Ziad , Smith Mike , De Moraes Flavio Dias 
Published: January 2011

Abstract
The Cascade and Chinook fields are located in the Gulf of Mexico (GOM), 250 miles south of New Orleans in ultra deepwater depths between 8200 ft and 8900 ft. The oil producing reservoir is in the Lower Tertiary Wilcox formation with a gross sand thickness of 1200 ft. The reservoir mid-point is at anaverage depth of 25, 600’ TVD with a bottomhole pressure of 19,500 psi and a bottomhole temperature of 260°F. The reservoir is comprised of vertically stacked thin beds of sand and fine grained siltstone intervals with effectively no vertical permeability. Additional information on this project can be found in a paper written by Moraes el al (2010).
Multiple limitations were considered during the initial design phase of the frac pack program. Thefracs were designed taking into account the use of a Single-Trip Multi-Zone sand control system. Although this system was not crucial in the overall implementation of the frac program, it added additional complexity from an operation stand point due to a continuous, multi-stage frac operation. Some ofthe operation limitations included service tool erosion limitations due to maximum pump rates and proppant volumes, overall frac vessel capacity, boat-to-boat fluid transfers and crew fatigue. The geological complexities of the reservoir were another major challenge in completing this very thick interval. Perforation intervals had to be placed to avoid a fault (and thus a potential early screenout), avoid a water contact, comply with tool spacing limitations and still maximize contact with net pay.
This paper addresses the approach taken to develop a fracture stimulation program for the Lower Tertiary formation in the Cascade and Chinook fields. Some of the major questions addressed during thisprocess include the following: how many fracture treatments are needed, what is the optimum fracture geometry, what is the desired conductivity, how to effectively position the perforation intervals, what is the desired pump rate and is a high-density fluid needed to fracture this deep, high- pressure formation? The approach, the answers and the treatment are discussed along with responses to additional questions that arose during the actual fracturing operations.
Along with the Lower Tertiary in the GOM, the industry faces similar challenges around the world. These include reservoirs with potentially large reserves but much lower permeability (due to depth and in-situ stresses) where fracturing is required for both stimulation and potential formation collapse sand control. Careful planning is necessary to avoid costly learning curves in these environments.
Life-Cycle Decline Curve Estimation for Tight/Shale Reservoirs
Authors: Ambrose Ray J. , Clarkson C. R. , Youngblood Jerry , Adams Rod , Nguyen Phuong , Nobakht M. , Biseda Brent 
Published: January 2011

Abstract
Low-permeability (tight) and shale (gas and oil) reservoirs have emerged as a significant source of energy in North America. Recent advances in technology, such as long horizontal lateral/multi-lateral drilling combined with hydraulic fracturing, and new surveillance techniques, have enabled commercial production from ultra-low permeability reservoirs, previously considered source or cap-rock, not reservoirs. Forecasting well production for reserves estimation, hydraulic fracture stimulation optimization, and development planning remains a challenge because of complex reservoir behavior and flow geometries associated with current wellbore architectures/stimulation treatments used to exploit tight formations. Depending on the completion design, transient flow periods can last for weeks to years, and hence traditional methods requiring boundary-dominated flow are strictly inapplicable for most of the commercial life of many wells completed in tight formations.
Recently, several analytical (type-curve, flow-regime analysis and simulation) and empirical approaches have been introduced to match and forecast tight reservoir production. The challenge is to develop routine techniques that can be used to forecast tight formation production, while adequately addressing the complex physics of the problem.
In this work, we build on recent attempts to combine analytical and empirical methods ("hybrid" methods) for forecasting tight/shale gas reservoirs completed with multi-fractured horizontal wells. We forecast the homogenous completion (equal hydraulic fracture length) case using established analytical procedures for transient linear flow (pre fracture interference), combined with the Arps decline curve for late-time (boundary-dominated) flow. We also examine the heterogeneous completion (unequal hydraulic fracture length) case to establish the impact of heterogeneities on decline characteristics post fracture-interference. Finally, we present an innovative method for designing hydraulic fracture and well spacing.