bluuebunny/crossref_metadata_2025_split huggingface dataset:
Diagnosis of Fracture Flow Conditions with Acoustic Sensing
Authors: Martinez R. , Hill A. D. , Zhu D. 
Published: June 2014

Abstract
Distributed acoustic sensing (DAS) is an emerging technology in hydraulic fracture diagnosis. Current uses of DAS systems have been limited to qualitative analyses that pinpoint noise sources, such as injection into formation or production from a fracture. This locating of noise verifies that injection or production is happening and its sound intensities at the different stages give a relative indication as to which stages took more fluid or produced more fluid post-treatment.
In this paper we used signal processing techniques and quantitative analysis to measure flow rates in a simulated fractured well. Production into a 5-½ inch ID well was simulated by injecting fluid through a one-foot long packed bed of 16/30 mesh proppant. Gas was injected at varying rates into the fracture and into the well. The noise produced from production was recorded with a hydrophone. The acoustic signal was transformed from the time domain to the frequency domain through a fast Fourier transform (FFT) for analysis.
The experimental results showed that the frequency of sound and its intensity were crucial in determining the amount of fluid being produced. The sound level of the peak frequencies were found to be linearly related to the flow rate. The results verified that sound alone can be used to measure flow rate through a proppant packed fracture or perforation tunnel.
Determining the fluid properties and flow rate can be achieved with DAS systems if the sound frequencies in addition to sound intensity are monitored. Incorporation of this technique into current DAS systems can give a real time value for injection rates during hydraulic fracture treatments and values for production rates from post treatment measure
Application of Integrated Advanced Diagnostics and Modeling to Improve Hydraulic Fracture Stimulation Analysis and Optimization
Authors: Ugueto Gustavo A. , Ehiwario Michael , Grae Abram , Molenaar Mathieu , McCoy Kelly , Huckabee Paul , Barree Bob 
Published: June 2014

Abstract
Economic development of unconventional resources relies heavily on the effectiveness of propped hydraulic fracture stimulation treatments (HFS or "fracs"). Non-stimulated and/or under-stimulated reservoir continues to be a critical industry concern. Mitigation is expensive and may require refracturing and/or additional wells to be drilled. Techniques to monitor and diagnose the geometry of HFS are limited and analysis typically has large uncertainties. This paper summarizes multiple datasets to demonstrate how complementary diagnostics significantly reduce uncertainties in their analysis, help to calibrate frac models and improve completion design of multi-stage wells. Diagnostics utilized in the datasets include: fiber optic distributed sensing (acoustic & temperature), non-radioactive tracers and production logs. We found that integrating these complementary diagnostics with other subsurface and well information not only confirmed that actual frac heights were different than intended in about half of the monitored stages, but also provided new insights that allow us to modify the HFS treatment design to better match the desired geometries. These diagnostics were used to history match and calibrate our frac models, allowing us to extrapolate results from the few wells with diagnostics to additional wells in the field. Statistics are also provided for the datasets including: percentages of perforation clusters and net sand treated to demonstrate the potential opportunity for improved stimulations and reserves recovery.
Economic Optimization of Horizontal Well Completions in Unconventional Reservoirs
Authors: Barree R. D. , Cox S. A. , Miskimins J. L. , Gilbert J. V. , Conway M. W. 
Published: June 2014

Abstract
Extrapolation of conventional paradigms to unconventional reservoirs can lead to disappointment and poor performance. Careful analysis of the reservoir and application of the correct stimulation design is critical when dealing with marginally economic developments. This includes adequate characterization of the reservoir and an understanding of the factors that control flow capacity and deliverability.
One of the biggest practical problems with unconventional stimulation design optimization is estimating post-fracture rate, production decline and ultimate recovery. Without a realistic prediction of the decline resulting from a given completion it is impossible to assign value to one design over another and equally impossible to optimize the treatment for whichever goal is sought, either acceleration of recovery or increase in reserves.
It is often the first - inadequate reservoir characterization - that leads to the second - unrealistic post-treatment predictions. For instance, assuming core-derived permeability fully represents the reservoir's total flow capacity or that stimulated reservoir volumes represent the effective producing volumes, can lead to incorrect diagnosis of the reservoir capability and consequently, lead to an inefficient treatment design.
This paper presents methods for production forecasting that give reasonable post-treatment predictions that have been found useful for economic planning. The proposed methodology, backed by field observations and laboratory work, provides an economically viable plan for optimizing lateral length, fracture spacing, and treatment design. The methodology focuses on the post simulation effective reservoir volume. Results show that increasing apparent fracture length rarely impacts long term recovery. Likewise, adding more fractures within the same reservoir volume may increase early time production rate (IP) and decline rate, without contacting more reservoir volume or adding to long term recovery. Such practices lead to acceleration of reserve recovery, which has economic value and should be considered in the design process, but does not increase the well's ultimate recovery once a sufficient number of fractures are in place. The economically preferred completion designs may be more driven by the net present value derived in the first five years of production rather than focusing on 20-50 year EUR's. This period represents most of the useful economic life of the well, can be estimated more accurately from early performance and therefore is a good benchmark for completion optimization.
A Fully Coupled Geomechanics and Fluid Flow Model for Proppant Pack Failure and Fracture Conductivity Damage Analysis
Authors: Han Jiahang , Wang John Yilin , Puri Virendra 
Published: June 2014

Abstract
One reason of observed reductions in the conductivity of hydraulic fracture is failure of proppant pack under the stresses. Proppant deformation, crushing or embedment can decrease the fracture width and conductivity. In this paper, continuity equation and momentum balance equation were fully coupled to simulate the transient phenomena involving fluid flow through a deformable porous proppant pack. Porous media displacement, water pressure, and gas pressure were derived as primary unknowns. The governing equation was discretized using the finite element method and solved numerically. In this model, proppant pack and formation rocks were treated as two different types of continuous porous mediums (Biot type). Proppant deformation, crushing, and embedment could be identified through the geomechanical model, while the damage effects on gas/oil production would be studied through the fluid flow model. Analysis of proppant deformation and crushing was based on the proppant pack stress-strain behavior. The displacement on fracture-formation interface represented the proppant embedment. Mohr-Coulomb failure was used as the criteria for proppant crushing. Effects of proppant damage were evaluated on proppant pack porosity and permeability. The model can be applied in all the hydraulically fractured reservoir with proper inputs. In this paper, we used fractured tight sand gas reservoir as a study case. The pressure distribution as well as proppant pack deformation were illustrated in the paper. Proppant pack mechanical behavior was found to be sensitive to the fluid flow pressure and proppants near wellbore was under higher possibility of being crushed.
A Statistical Study of Proppant Type vs. Well Performance in the Bakken Central Basin
Authors: Flowers J. R. , Guetta D. R. , Stephenson C. J. , Jeremie P. , d'Arco N. 
Published: June 2014

Abstract
Every new oil and gas development goes through a typical growth cycle starting with the discovery well. A large part of that growth process is optimizing the well completion techniques ad this tends to be the most difficult process to optimize due to the difficulty in measuring the success or failure of these changes. When modifications are made in the drilling process results can be measured almost immediately while changes in well completions can take months or years to evaluate and require the analysis of many variables.
Determining the optimal fracturing treatment in North Dakota's Bakken has been a widely discussed topic in recent years. Data from field trials, which focus on a few dozen wells, provide broadly contradicting claims regarding the ideal proppant that should be used in the fracture treatment. This lack of agreement results in a disparity between treatment practices in otherwise geographically close wells that are completed in similar formations. This paper will utilize a statistically significant volume of publicly available, operator-originated data, with the intent of making a data-driven determination regarding the optimal treatment.
This paper combines production data from the North Dakota Industrial Commission (NDIC) and completion reports from the publicly accessible FracFocus 2.0 database which contains over 2,900 well records from the Bakken. The statistical analysis of this data reveals a correlation between the proppant type used and the well performance in the Bakken Formation.
This data was pared down to concentrate on the Central Basin which consists of McKenzie and Williams counties. Comparing the long term performance of 205 wells from this area indicates a clear advantage of ceramic proppants over other proppant types. The results of this analysis show that ceramic proppants result in a slower production decline which leads to significant increases (20-40%) in 6 month and 1 year cumulative production. This increase in well production more than offsets any additional completion cost resulting in an improved ROI.
Limited Height Growth and Reduced Opening of Hydraulic Fractures due to Fracture Offsets: An XFEM Application
Authors: Abbas Safdar , Gordeliy Elizaveta , Peirce Anthony , Lecampion Brice , Chuprakov Dimitry , Prioul Romain 
Published: June 2014

Abstract
Hydraulic fracture propagation through a layered medium often exhibits a complex fracture path due to lateral shifting of the fracture path after passing through an interface. The existence of these offsets in the fracture path has been confirmed by mapping of mined fractures and by laboratory experiments. In addition to the stress contrast and material contrast, these offsets act as another mechanism for fracture-height containment. In order to investigate fracture height growth problem, we have considered a case of plane-strain fractures propagating from an injection point and propagating in a predetermined path. Fracture offsets of a given length and angle are prescribed within the predetermined path. In this way, we parametrize the problem of fracture offsets in order to quantify their effects on the fracture height growth and fracture opening reduction at the fracture offset (pinching effect). This is done while keeping a hydrostatic state of confining stresses in order to observe only the geometric effect of the fracture offset. We use a recently developed hydraulic fracturing code based on the eXtended Finite Element Method (XFEM). This code solves the fluid flow in the fracture and the elastic response of the fracture in a fully coupled manner solving for the fracture velocity using the complete hydraulic fracture tip asymptotics.
For different combinations of independent parameters (i.e., formation moduli, far-field stresses, fluid injection rate, ratio of offset length to the length of the straight fracture and the offset angles) we investigate the effect on the fracture height growth and the reduction in fracture opening at the fracture offset. A detailed parametric study shows that while each parameter affects the fracture height containment, the fracture opening reduction is dominated by the fracture offset angle which is a geometric effect of the fracture offsets. This has a profound effect on the proppant bridging at the fracture offset.
On the Mechanisms of Shale Microfracture Propagation
Authors: Padin Anton , Tutuncu Azra N. , Sonnenberg Steve 
Published: June 2014

Abstract
Economical production rates in shale reservoirs are achieved solely by hydraulic fracturing the pay zones on horizontal wells with multiple stages, thus this technique is an essential tool for the development of enormous reserves of oil and gas in the United States. However, the processes that dominate hydraulic fracturing in shale reservoirs are poorly understood, and the variability of the properties from one shale play to another makes this learning process intricate. In this paper, we investigate the evidence of microfracture propagation on ductile shales and the key factors that constrain its slippage. First of all, we present evidence from the study of two reservoirs, the Eagle Ford formation in South Texas and the Vaca Muerta formation in Argentina. Secondly, we analyze the key parameters that affect flow through microfractures in organic-rich mudstones. We identify the key variables used to characterize these reservoirs through integration of geomechanics laboratory experiments with microseismic monitoring, mineralogy, organic carbon content, fabric, log, core, geological and field data analysis. Our ultimate goal is to identify the main parameters that influence fracture flow from very tight shales with the ultimate goal of optimizing the completion design in these complex formations. With this objective in mind, we examine the relatively slow slip process of tensile fracture growth in ductile, high clay and organic content shales, which results in the reactivation of preexisting horizontal fractures, producing aseismic energy. We then compare this mechanism against the fast shearing deformation that generates microseismicity in brittle shales. By observing the differences between the macro-scale (microseismic, anisotropy of the acoustic waves, geomechanics experiments), the meso-scale (fabric-thin section) and the micro- and nano-scales (clay particles) we suggest that the mechanisms of fracturing on ductile versus brittle rock are seen at any scale; that the anisotropy of the fabric of the rock within the interface between clay and non-clay minerals that differ in size and strength, the anisotropy of the horizontal stresses, the overpressure conditions, the friction angle of kerogen, the orientation of the pre-existing microfracture network with respect to the current stress state and –to a lesser extent- the elastic moduli of the rock matrix, are the most significant parameters that dominate microfracture propagation mechanisms on organically-rich rocks. The systematic integration of data from two analogous shale reservoirs and its comparison against existing theories on the mechanisms of fracture propagation has the benefit of approaching the process of fracturing from a predictive perspective, with potential benefits on stimulation optimization.
Application of Multivariate Statistical Modeling and Geographic Information Systems Pattern-Recognition Analysis to Production Results in the Eagle Ford Formation of South Texas
Authors: LaFollette Randy F. , Izadi Ghazal , Zhong Ming 
Published: June 2014

Abstract
As of this date, approximately 5,000 horizontal Eagle Ford wells have been completed in South Texas. Still, geologists and engineers question whether their companies are using the most appropriate operating practices. Side-by-side case studies may show value or not, given the challenge of small sample size and hidden influences on outcome. Multivariate statistical analysis of larger data sets offers sound interpretation across larger geographic areas, with the caveat that correlations need to be scaled to local conditions. The purpose of this paper is to apply multivariate statistical modeling in conjunction with Geographic Information Systems (GIS) pattern recognition work to the Eagle Ford.
The investigation began by acquiring Eagle Ford data using both proprietary and public information. The different data sets were loaded into a common database and put through quality control sanity checks. Production proxies, such as maximum oil rate in the first 12 producing months and normalized 12 month cumulative production, were selected and merged with the other data. Final data sets were then subjected to analysis in both an open-source multivariate statistical analysis and visualization code and a commercial Geographic Information Systems (GIS) application.
Similar to other studies in unconventional reservoirs, integration of the two analysis and interpretation methods highlighted the importance of using well location as a proxy for reservoir quality when working with data sets that lack such measurements. The use of multivariate statistical analysis allowed modeling the impact of particular well architecture, completion, and stimulation parameters on the production outcome by integrating out the impact of other variables in the system.
This work is a continuation of the prior work designed to address well optimization in unconventional reservoirs. It is significant in that it takes full advantage of GIS map-based methods and multivariate statistical methods to capitalize on the volume of data available through the public domain.
Impact of Accurate Fractured Reservoir Flow Modeling on Recovery Predictions
Authors: Singh G. , Pencheva G. , Kumar K. , Wick T. , Ganis B. , Wheeler M. F. 
Published: June 2014

Abstract
The design and evaluation of hydraulic fracture modeling is critical for efficient production from tight gas and shale plays. The efficiency of fracturing jobs depends on the interaction between hydraulic (induced) and naturally occurring discrete fractures. We describe a coupled reservoir-fracture flow model which accounts for varying reservoir geometries and complexities including non-planar fractures, faults and barriers. In addition our model is coupled with linear elasticity using iterative coupling to solve a multi-phase Biot system. The approach presented here is in contrast with existing averaging approaches such as dual and discrete-dual porosity models where the effects of fractures are averaged out. We model the fractures and reservoirs explicitly, which allows us to capture the flow details and impact of fractures more accurately. Moreover, accurate modeling of solid deformations necessitates a better estimation of fluid pressure inside fracture, which our flow model provides. We utilize different flow models for the fractures and the reservoir closely capturing physics when needed. A quantitative comparison is made in order to identify situations where a multiphysics flow description is critical to accurate prediction compared to an averaging based approach. We present several numerical tests, including a field scale case study, to illustrate the above features and their impact on recovery predictions.
New Technology Yields Ultra High-Strength Proppant
Authors: Palisch Terry , Wilson Brett , Duenckel Bob 
Published: June 2014

Abstract
Nearly all of the proppant available on the market today can be classified into one of three tiers - sand, resin-coated sand and ceramic. The products contained in these three tiers have served the industry well and have typically covered the broad spectrum of applications required by completions engineers. However, with the development of deeper reservoirs as well as the ongoing look at geothermal and steam-flood applications, there now exists a gap in proppant technology. No conventional proppant can provide the required conductivity at the 20,000 psi closure stresses (and higher) anticipated in the Lower Tertiary formations in the deep Gulf of Mexico. Similarly, no conventional proppant can adequately withstand the harsh chemical conditions in many geothermal and steam-flood applications.
A new proppant has been developed and commercialized to meet these challenges, achieving twice the baseline conductivity of any conventional proppant at these high stresses, and providing additional advantages with increased durability and longevity. This paper will review the step change advancements achieved by this new proppant, including technology improvements in both raw materials and manufacturing process. It will present properties never seen before regarding proppant shape, sizing and strength. Extensive laboratory testing has been completed to demonstrate the superior performance in harsh conditions, and will be presented.
The paper will also present the expected applications for this product, including areas where increased production rates, superior EUR, lower erosivity and reduced equipment wear are a premium. Field applications are beginning as of this writing.
This paper should be beneficial to all engineers and technologists currently working in stress applications greater than 15,000 psi, or other harsh conditions such as steam-flooding and geothermal applications.
A Comparison of the Effectiveness of Various Fracture Fluid Systems Used in Multi-Stage Fractured Horizontal Wells: Montney Formation, Unconventional Gas
Authors: Reynolds M. M. , Bachman R. C. , Peters W. E. 
Published: June 2014

Abstract
Recently, there has been discussion of the need to advance hydraulic fracturing technology from the current ‘operational effectiveness’ mode of high-rate slickwater fracture designs, to a ‘fracture effectiveness’ mode provided by optimizing designs to achieve higher recoveries and better economics. This case study shows how advanced fracture fluid system designs have increased fracture effectiveness in an area of the Montney unconventional gas play.
The study focused on fifty multi-stage fractured horizontal wells in the dry gas area of the Heritage Montney Field in British Columbia, Canada. These wells were stimulated by different operators with a number of different fracturing techniques, fluid systems, etc. Wells were selected such that a sufficient variety of completion techniques were represented, and there was over 18 months of production history. A thorough review of the geology and petrophysical data within the area was undertaken in order to develop individual well descriptions for use in the production analysis (Rate Transient Analysis). Wells were history matched by varying reservoir permeability and fracture treatment properties. The results demonstrate that fracture effectiveness is a function of the fracture type and has a large effect on well productivity and economics.
This case study shows there is value in optimizing fracture designs through look-back studies, and that there is a need to focus on more effective fracture treatment designs in unconventional gas development. The results of the study show the importance of fracture fluid selection as well as both effective fracture half-length and fracture conductivity in maximizing the economic returns in this area of the Montney.