bluuebunny/crossref_metadata_2025_split huggingface dataset:
Advanced Computational Modeling of Proppant Settling in Water Fractures for Shale Gas Production
Authors: Tsai Kuochen , Fonseca Ernesto Rafael , Degaleesan Sujatha , Lake Ed 
Published: December 2012

Abstract
This paper shows advances in the numerical simulation of proppant transport in hydraulically stimulated fractures for oil and gas production. Water or commonly known "slickwater" hydraulic fracture treatments have become increasingly popular in shale gas. This is widely applied in the Haynesville shale in north Louisiana but, due to the large depths and high pressure, conventional wisdom requires that the intermediate strength proppants (generally 4,000 to 6,000 psi crush strength) should be used. This strength envelope is in the transition between ceramics and sand. Sand, which is lower in cost, also has the advantage of having better transport properties in water fractures.
In the paper, a 3-D computational fluid dynamics model with Lagrangian solid particle transport isused to visualize the propagation of sand and other lighter proppants in a simulated fracture. Demonstrated is the proppant settling behavior influenced by proppant density, size and flow rates. The final proppant settling patterns can vary dramatically and may result in significant changes on the fracture’s conductivity.
Model assumptions, simplifications and numerical details are discussed along with issues regardingvalidation and simulation strategy. The model geometry is highly idealized (i.e., neglectingfracture tortuosity and expansion during water fracturing, surface roughness and fluid leakoff). The importance of this work lies in the fact that the model can resolve the interactions between fracturing fluid (water) and proppants within complex 3-D geometries, thus providing a better understanding of the fracturing process to allow for possible enhancements to production procedures.
Revisiting Natural Proppants for Hydraulic Fracture Production Optimization
Authors: Yang Mei , Economides Michael J. 
Published: December 2012

Abstract
Proppants are essential to the success of most hydraulic fractures and often account for the overwhelming cost of the treatment. Both the mass of proppant and the selection of the right type of proppant are essential elements in gaining the highest Net Present Value (NPV).
It has been generally believed that in the lower closure stress environment (below 6,000 psi, i.e., shallow reservoirs), natural sands such as Brady and Ottawa are appropriate as proppants and, for the same mesh size, they provide essentially the same permeability. Commonly accepted notion is that manmade proppants (such as ceramics) should be applied at higher closure stress environment, invariably, deeper reservoirs.
Three types of proppants are studied for a gas reservoir of Eagle Ford basin: Brady sand, Ottawa sand and ceramic. A fracture optimization p-3D model is used to maximize well performance by optimizing fracture geometry, including fracture half length, width and height. Reduced proppant pack permeability is compensated by larger width. Non-Darcy effects in the fracture are also considered. Post-treatment well performance is then estimated, using the optimized well geometry, leading to cumulative production over the well life. Finally, NPV analysis is employed as the criterion to select the best proppant for the job.
In this project, we show there is an optimum Proppant Number corresponding to maximum NPV in various reservoir permeability. Based on that, we propose a systematic way of choosing proppant type and mass to maximize NPV in oil reservoirs. For tight gas reservoirs, we correct the prejudice that natural sand proppants cannot be applied to deeper reservoirs by showing NPV study results that are superior to those of manmade proppants. Keeping stimulation costs down, natural sands proppants have a much larger range of applicability than previously thought.
Numerical Modeling of Fracture Complexity With Application to Production Stimulation
Authors: Shen Xinpu , Cullick A. S. 
Published: December 2012

Abstract
The commercial exploitation of shale resources requires the design of hydraulic fracture programs to optimize the stimulated reservoir volume. Challenges include the engineering of staging, sequencing, injection volume, and proppant selection. This paper describes the development of a 3-D finite-element model to simulate growth of fracture complexes as functions of rock stress, brittleness properties, and injection conditions. The fracture complex is modeled as a major fracture, which consists of a cohesive crack and microcracks that form with variable continuum mechanical damage. Variations of permeability and porosity affect the continuum mechanical damage, which is used to investigate the fracturing sequence of three stages of injections in a horizontal well and generates three sets of fracture complexes. Inputs include a geomodel, the initial geostress, and pore pressure. Elastoplastic deformation coupled with both porous and gap flows are simulated.
The model is also used to investigate the influence of rock brittleness on the fracture complexity. Material brittleness is the product of the elasticity modulus and Poisson’s ratio. Three sets of values of material brittleness were used in the calculation for comparison. The same loads and initial conditions of the first example were used in the model. The results include two sets of distributions of fracture propagation and damage evolution for two different injection sequences, pore pressure distribution after fluid injection stimulation, three sets of numerical results of distribution of fracture, and mechanical damage corresponding to different values of brittleness. Numerical results indicate that adjusting the sequence of multi-stage fracturing significantly influences the stimulated formation volume fractured. The model can be used to design more optimal fracture programs.
Proppant Fracture Conductivity With High Proppant Loading and High Closure Stress
Authors: Rivers M. , Zhu D. , Hill A.D. 
Published: December 2012

Abstract
Ultra-deepwater reservoirs are important unconventional reservoirs that have the potential to produce billions of barrels of hydrocarbons, and are usually high pressure and high temperature with relatively high permeability. One major challenge of an unconventional, ultra-deepwater reservoir is pumping an effective and robust fracture stimulation treatment. Hydraulic fracturing a high permeability reservoir (&gt;100 md) can be different from hydraulic fracturing technology used in low permeability formations (&lt;1 md) due to their difference in purpose. The main purpose of hydraulic fracturing a low permeability reservoir is to create a long, conductive path to enhance drainage area and ensure a commericially economic well. In a high permeability formation, hydraulic fracturing is predominantly used to bypass near wellbore formation damage, control sand production and reduce near wellbore pressure drop. Such a treatment is achieved by pumping a short fracture packed with high proppant concentrations and may also aim at achieving enough fracture length to increase productivity especially when reservoir fluid viscosity is high. To pump such a job and ensure long term productivity from the fracture, understanding the behavior of the proppant pack is critical.
A series of laboratory experiments have been conducted to study conductivity and fracture width with high proppant loading, high temperature and high pressure using a Cooke conductivity cell. In thisstudy, proppant was manually placed between two core samples and fracture fluid was initially pumped through the proppant pack. Conductivity was subsequently measured by pumping oil through the manuallyplaced proppant pack to displace the fracture fluid and simulate reservoir conditions; resulting fracture fluid clean-up and proppant pack performance were studied. High strength proppant, ideal for fracture stimulations with high closure stress, was used to study the effects of proppant fracture conductivity with different proppant loadings and closure stresses. Proppant crushing and fracture width were also measured and compared to proppant pack conductivity in certain cases.
Testing results while pumping oil through the proppant pack at reservoir conditions indicated almost immediate fracture fluid clean-up. Increasing proppant concentration in the fracture showed higherconductivity values in some cases, while increasing the effective closure stress during an individualtest resulted in a significant loss in conductivity for all cases. Additionally, fracture width decreased with increased effective closure stress and time. Tests were also run to study the effect of cyclic loading and showed further degradation in conductivity and width.
First Application of Just-In-Time Perforating in a Horizontal Well
Authors: Angeles Renzo , Tolman Randy , Ross Kirk , Burnham Heather , El-Rabaa Wadood 
Published: December 2012

abstract
Just-In-Time-Perforating (JITP) was developed by ExxonMobil over a decade ago to improve multi-zone stimulation in vertical and S-shaped wells in the Piceance basin, Colorado. With this technology, multiple single-zone fracture stimulations are performed on a single wireline run using ball sealers and perforating guns that remain downhole during the fracturing treatment. This results in substantial cost reduction and productivity uplift because perforation intervals are individually and effectively treated one at a time with less horse power, smaller number of frac plugs, and fewer wireline runs. The method has been successfully implemented by ExxonMobil in more than 350 wells and over 10,000 treatments and is licensed to a number of service companies.
There is substantial business incentive to implement the JITP technique in horizontal wells, extensively used in unconventional gas developments. With XTO Energy joining ExxonMobil, the global gas portfolio incremented by 45 trillion cubic feet. This includes conventional gas, shale gas as well as other unconventional resources, such as tight gas, coal bed methane, and shale oil.
This paper presents the first application of JITP in horizontal wells. Operations were conducted in the Fayetteville Shale, Arkansas. The paper discusses advantages and disadvantages of the method as well as lessons learned from pre-field trials and full-well implementations. Critical to the success of the initial technology application was the enforcement of a structured approach which included technical feasibility studies, contractor qualification, pre-field trials, well candidate selection, and a deployment plan to capture learnings and best practices. Pre-field trials were executed in several wells to test potential technical/operational concerns, such as sand build-up around perforating guns, fluid diversion with buoyant and non-buoyant ball sealers, and the ability to move guns through the lateral. Preliminary field costs and production performance in horizontal wells are promising and support continued deployment of the technology.
Field Development Study: Channel Fracturing Increases Gas Production and Improves Polymer Recovery in Burgos Basin, Mexico North
Authors: Valenzuela A. , Guzmán J. , Chávez S. , Mondragón G. García , Gutiérrez L. , Exler V. , Ramírez C. , Parra P. , Peña A. 
Published: December 2012

Abstract
The channel fracturing technique combines fracture modeling, materials and pumping methods to generate a network of highly conductive channels within the proppant pack. These channels aim at expediting the delivery of hydrocarbons from the reservoir to the wellbore (Gillard et al., 2010). This paper provides a comprehensive summary of the implementation of this novel technique in the Burgos basin, Mexico North.
The Eocene Yegua formation in the Palmito field near Reynosa, Mexico was selected for this study. This formation comprises sandstone layers with average permeability of 0.5 mD and Young’s modulus in the order of 2.5 Mpsi. Key historical issues for the stimulation of this formation using conventional fracturing materials are limited polymer recovery and the consequential fracture conductivity impairment. Use of resin-coated proppants has also been implemented to prevent proppant flowback from these operations.
Gas production, treating pressure and polymer recovery data from a twelve-well campaign in the Palmito field (six wells treated via channel fracturing, six offset wells treated conventionally and aiming for similar fracture geometry) are summarized in the manuscript. Results indicate that the implementation of the channel fracturing technique improved fluid and polymer recovery, thus leading to increases in initial gas production by 32% and 6-month cumulative gas production by 19%. Such improvements in production were obtained with 50% less proppant per stage and smaller proppant particles. These observations are consistent with the hypothesis that the channel fracturing technique promotes the decoupling of fracture conductivity from proppant pack permeability. Positive features that were also observed during this campaign such as absence of proppant flowback issues without the use of resin-coated sand and non-occurrence of near-wellbore screen-outs are also reported and discussed.
The study concluded that the channel fracturing technique is a viable alternative to conventional fracturing methods for the stimulation of wells in the Burgos basin.
Two-Phase Production Analysis for Hydraulically Fractured Reservoirs
Authors: Klinsky A. , Callard J. 
Published: December 2012

Abstract
The resource play development cycle is a continuous loop that constitutes hydraulic fracture stimulation, production analysis, and redesign of subsequent stimulation treatments. Objectives of the cycle include optimizing lateral length, cluster spacing, injected volumes and types of proppants and fracturing fluids. During the stimulation process, leak-off invasion of the hydraulic fluid to the formation occurs and the fracture is left completely saturated with fracture fluid. Consequently, initial production is transient two-phase flow. One aim of this work is to improve analysis during this two -phase flow period. Production analysis has been a fundamental tool in analyzing hydraulically stimulated reservoirs. Previously presented work is based on single phase flow. For shale gas reservoirs, gas production increases during clean-up; this can occur at the end of fracture linear flow or may continue into the bilinear flow period due to the continued recovery of frac load fluid. This work investigates transient two-phase flow exhibited in multi-stage hydraulically-fractured shale gas reservoirs as well as terminal production after stage competition instigates boundary dominated flow. The effect of relative permeability, fracture storage capacity and fracture conductivity on the production behavior including bilinear and formation linear flow is investigated by the means of parametric studies utilizing numerical simulation. Cluster spacing is used as a parameter in the boundary dominated production period. This analysis is applied to field production data and case histories are presented. Results of this investigation are summarized in decline type curves.
Building Acid Frac Conductivity in Highly-Confined Carbonates
Authors: Neumann L F , Oliveira T J , Fernandes P D , de Oliveira e Sousa J L , Brandão E M 
Published: December 2012

Abstract
The deep and hard limestones found off-shore Brazil are being extensively evaluated, and some of them would require stimulation to enable commercial development. The main objective of this paper is to discuss the feasibility of acid fracturing stimulation in hard carbonates. Laboratory test are performed to verify whether an acid-induced fracture can withstand the high effective normal stresses expected during the exploitation stage of pre-salt development, keeping an acceptable conductivity. There is no agreement in the technical community regarding the survival of an acid fracture at closure stress greater than 5,000 psi. However, the experience that leads to this controversy is mainly based on: (1) wells on land and, (2) few published tests on rocks with mechanical properties compatible with those depths. An experimental program has been designed to evaluate these chances of acid fracture survival. A few initial essays with samples of these carbonate rocks have shown significantly higher rock strength than those commonly found in the literature. Initially, the Nierode & Kruk correlation (1973) is used to predict fracture conductivity behavior. Both mechanical strength and dissolved rock equivalent conductivity are measured from outcrops, and from soft and hard offshore carbonates samples. This work reports the results with outcrops and reservoir samples, in order to assess whether the adopted experimental methodology is consistent and reproducible. Some topics about acid fracture conductivity prediction are also addressed. Further research should be performed with pre-salt rock samples using the same procedures.
A Direct Comparison of Hydraulic Fracture Geometry and Well Performance Between Cemented Liner and Open Hole Packer Completed Horizontal Wells in a Tight Gas Reservoir
Authors: Reynolds Murray , Thomson Susan , Peyman Faezeh , Hung Allan , Quirk David , Chen Shaoyuan 
Published: December 2012

Abstract
The Glauconitic formation is a Cretaceous age sandstone reservoir located across a large area of central Alberta, Canada. Discovered in the late 1970’s, hydraulically fractured vertical wells could produce commercial volumes of natural gas from some of the higher permeability conventional sands. However, wide spread development of the majority of the tight gas sands was not economic with vertical wells.
With the introduction of multiple fractured horizontal well (MFHW) technology in recent years, and much better definition of the geology, a large unconventional resource play has developed in the Glauconitic, which could contain in excess of 5 tcf of gas in place plus associated natural gas liquids (Scotia Capital, 2009).
A pilot project was designed to test the completion effectiveness between a cased and cemented liner and an open hole packer system in this tight gas reservoir. Two vertical microseismic observation wells were located in close proximity to two proposed horizontal wellbores, giving ideal conditions to test how the hydraulic fractures would grow and the ultimate fracture geometry, from two different completion methods.
In this paper we will present the microseismic results of the pilot project, as well as the early production history comparison between the two wells, and the hydraulic fracture effectiveness from a reservoir engineering aspect.
Eco-Friendly Creation of Propped Hydraulic Fractures
Authors: Cooke C. E. , Watters J. T. , Watters L. T. , Wann S. R. , Zhu D. , Hwang Y. S. 
Published: December 2012

Abstract
A novel method for creating short, highly conductive fractures in wells to bypass formation damage has been developed. The method uses relatively small material volumes, low horsepower and pump rate, produces minimal environment effect, and leaves the formation face and proppant pack residue free. Function and application of the method present significant varia-tions in treatment design and execution compared to traditional hydraulic fracturing past damage. This paper presents results of development work to confirm the method’s applicability and to provide sufficient performance data to design initial field applications.
Fiber Optic Distributed Acoustic Sensing of Multiple Fractures in a Horizontal Well
Authors: MacPhail Warren , Lisoway Bill , Banks Kevin 
Published: December 2012

Abstract
This paper highlights the current state of fiber optic distributed acoustic sensing (DAS) technology by reviewing its application to hydraulic fracture diagnostics in a multi fractured horizontal well (MFHW). It will be shown that, with the advent of DAS, a gap in the feedback — which could previously occur using various hydraulic fracture diagnostic options — has been filled. Results are shared that were obtained from the first successful application of high resolution DAS during the placement of multiple hydraulic fractures in a horizontal well that was completed with an open hole packer and frac valve system.
Observations of the real time acoustic soundfield in the near wellbore (NWB) region during hydraulic fracturing are presented as high resolution images. These images have enabled an analysis of key dynamic aspects of the fracturing process. In examining the resultant data, it has become apparent that DAS has overcome some limitations intrinsic in other diagnostic tools such as distributed temperature sensing (DTS), microseismic monitoring, and tracer programs. An overview of the well design is provided as well as selected samples from the dataset which highlight some of the events that were observed during the hydraulic fracturing process. Sample images are used to demonstrate the current capability of DAS measurement, selected both from the real time soundfield display (SFD) and from processed high resolution soundfield maps. DAS processing methods are briefly discussed, as well as two categories of field observations— which highlight some of the mechanical reliability aspects of the swell packer/ball actuated frac sleeve system, as well as some aspects of the near wellbore region during hydraulic fracturing such as single or multiple fracture initiation sites and the general behaviour of wellbore fluids over the course of the fracture treatment.
Distributed acoustic sensing using a single mode optic fiber has been described in recent literature (Molenaar, 2011) for applications involving the recording of acoustic events during various stages of well completion and stimulation. The current paper provides further description on how DAS works and shares results from a high resolution DAS survey, obtained while placing multiple hydraulic fractures in a horizontal well, completed in a tight sand using an openhole ball actuated valve system with swell packers for fracture isolation. Earlier findings are supported, in particular that DAS will enable an improved understanding of in-wellbore activities and, in so doing, that it will enable optimization of hydraulic fracturing design and execution. It is recognized that much is yet to be learned in the processing of fiber optic DAS data, but also that it would be beneficial to share the work that has been completed to date to facilitate accelerated development of DAS processing technology.