bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimization of Hydraulic Fractures in Tight-Oil Reservoirs Using Different Numerical Fracture Models
Authors: Temizel Cenk , Energy Aera , Betancourt Dayanara , Aktas Sinem , Susuz Onur , Zhu Ying , Suhag Anuj , Ranjith Rahul , Wang Aaron 
Published: August 2016

Abstract
Hydraulic fracturing is a very robust tool in terms of not only increasing production in tight reservoirs but also accelerating production from reservoirs with higher permeability and porosity. The success of a hydraulic fracturing treatment is highly correlated with control of the created fracture geometry. Control of fracture growth and geometry is challenging in formations where the boundary lithologies are not highly stressed compared to the pay zone, allowing out-of-zone migration of fractures. As several factors influence the growth and geometry of fractures, including the reservoir, wellbore, and fluid/proppant parameters, it requires a good understanding of reservoir parameters, including stress distribution along with appropriate use of corresponding wellbore components and fluid/proppant for successful and efficient results. Our objective is to outline the main differences between different fracture models along with the key parameters and their significance in fracture performance.
Fracture treatment designs involve selecting fracturing fluids, additives, proppant materials, injection rate, pump schedule, and fracture dimensions. Although hydraulic fracturing has become more important due to development of unconventional resources in tight formations, the use of fracture models before implementation of the treatment is limited, leading to undesired fractures either with limited growth or propagation out of zone. Literature lacks a study that combines the evaluation of different fracture models in an optimization process where economics is taken into account with an objective function maximizing the net present value (NPV), providing detailed information on the financial side of this technical phenomenon, too.
In this study, different numerical fracture models are used to design the fractures in a tight oil reservoir, the performance of designed fractures are analyzed to measure the success of different numerical models applied in design along with an overview of critical operational parameters together with the significance of parameters, including size, number, and location, phasing angle of perforations, fluid and proppant type, rock strength, porosity, and permeability on fracture design optimization‥
In our paper, a comprehensive literature review of previous studies on tight oil reservoirs and hydraulic fracturing provides a thorough theoretical comparison of fracture models used in oil industry along with the analysis of significance of each factor throughout the process of hydraulic fracturing tight oil reservoirs. An objective function that maximizes NPV is used in this study investigating the phenomenon not only from the physical but also the economical aspects of fracturing that is still an expensive but an effective way of production enhancement technique when applied wisely.
Successful Application of Seawater-Based Clean Fracturing Fluid
Authors: Prakash Chetan , Raykov Tzoni , Kolasa Bartlomiej , Belakshe Ravikant , Janiczek Peter 
Published: August 2016

Abstract
Seawater-based fracturing fluids are favorable in offshore locations because of the readily available seawater. This minimizes or even eliminates costly vessel trips that are necessary to transport fresh water to rig sites, while also reducing rig downtime. This paper presents the development of a low-residue fracturing fluid that uses seawater as a base fluid and the results of successful field applications.
This seawater-based fluid uses a low-residue polymer crosslinked with zirconium having a pH of less than 10 to minimize damage and residue encountered using other fluids. The fluid was tested for rheological properties, proppant-carrying capacity, retained permeability, and compatibility with formation fluid. To improve timing and efficiency of operations, multistage fracturing completion was used wherein each fracture sleeve was opened by dissolvable balls. Two sidetrack wells were treated in the offshore Romanian Lebada fields. Well A comprised high sandstone content. Well B comprised a higher limestone content but contained too much clay and sandstone for an acid fracturing treatment. Both wells exhibited a moderate-to-high number of natural fractures. Because of moderate permeabilities in the range of 0.1 to 2 md, crosslinked fluid was used in the pad and subsequent proppant-laden stages.
The seawater-based fracturing fluid was not expected to generate damaging effects on reservoir productivity. During development, the fluid remained stable for approximately 1 hour at 325°F with a gel loading of 6 kg/m3. The thermal stability of the fluid system was improved when compared to the alternative hydroxypropyl guar (HPG) fluid. A delayed crosslinker was used to maintain low-friction pressure during the treatment. No scale formation was observed. The target reservoir temperature was 199°F. Additional testing optimized gel loading at 3.6 kg/m3. The fluid suspended the proppant for approximately 2 hours. Less than 1% residue was formed after fluid breakdown, which was much lower than the residue generated by the HPG fluid. A regained permeability of 92% was obtained from a sandstone core, which demonstrates the low-damaging nature of the fluid. The broken fluid was fully compatible with crude oil and completion brine.
Eleven hydraulic fracturing operations were designed and executed successfully in both horizontal sidetrack wells. A 16/20-mesh resin-coated proppant (RCP) was used at a maximum concentration of 720 kg/m3 in the tail stage. A total of 851 tonnes of proppant was pumped in 3156-m3 crosslinked fluid.
The seawater-based fluid properties present an innovative approach to address the water requirement issue for offshore stimulation operations. This fluid is an excellent candidate for fracturing operations and can help operators maintain low costs per barrel of oil equivalent (BOE).
Leveraging Biotechnological Innovation for Improved Oil Production in Shale Formations: A Case Study
Authors: Sookprasong P. A. , Armstrong C. D. , DeBenedictis F. H. , Berhanu Hanna , Workneh Nigatu 
Published: August 2016

Abstract
The Bakken formation is one of the largest unconventional oil plays in the United States, and large-scale hydrocarbon recovery from this formation has only recently become economically feasible as technological advancements have reduced stimulation costs. These low-permeability zones must be fracture-stimulated with large fracture networks for enhanced well production and improved economics. Guar-based fracturing fluids are the most commonly used in stimulation treatments. Cross-linked fluids with low polymer loading and high viscosity are needed to transport proppant efficiently. However, due to the tight shale formation, efficient proppant pack cleanup is critical to minimize polymer residue.
The breaker systems include coated and uncoated oxidative breakers with an enzyme breaker added during the tail-in stages to break down the viscosity and aid in fracture fluid cleanup. In the field, oxidizers were found to perform inconsistently at some temperatures, and the conventional enzymes were inefficient at higher pH and temperatures.
To improve reliability, a novel enzyme breaker was field-tested in early 2010 and proven to function more consistently and enhance post-stimulation productivity. In late 2012 and early 2013, this new enzyme breaker was implemented in multiple fields and consistently yielded similar results as the field trials. The enzyme breaker is a polymer-specific, thermostable mannanohydrolase, genetically modified for increased conformational stability. This enzyme breaker can be used from ambient temperatures to ≥ 250°F and functions well at an elevated pH of 11.0, whereas conventional enzymes are inefficient under these conditions.
Production results from several wells were compared with offsets that had been treated with the conventional fluid system and breaker package. The wells treated with this new enzyme breaker showed higher increase in oil production. This demonstrated persistence of this new enzyme to improve breakdown of the polymer and enhance cleanup of the proppant pack which resulted in enhanced oil production.
Decipher Productivity Secret to Optimise Well Stimulation for Keshen Tight Gas Reservoir
Authors: Yang Xiangtong , Xu Jianhua , Zhang Yang , Wang Hao , Li Wei , Wang Lipeng , Fan Wentong 
Published: August 2016

Abstract
Keshen Gas Field is part of Kuqa Foreland thrust belt, located in Southern foothill of Tianshan Mountain, northern margin of the Tarim basin, West China. The main pay zone, Cretaceous Bashijiqike (K1bs), has extreme reservoir conditions of ultra-deep (6500-8000 m), high temperature (170-190°C), high pressure (110-120 MPa)(HTHP). Thick salt and gypsum layers with high dip angle above the pay zone also increase safety concerns during drilling and completion. Because of its low porosity (2-7%), low matrix permeability (0.001-0.5 md) and high heterogeneity of nature fractures (NF), well production rates vary largely, ranging from zero to 300,000 m3/d. Stimulation has become the only way to enhance single well performance and gain economic production for the long run. Finding controlling factors for well production and effective workflow is the key to realize efficient field development for this tight gas reservoir.
In this study, an integrated workflow covering comprehensive reservoir characterization (evaluations of geology, geophysics, geomechanics and reservoir engineering), engineering design and execution (stimulation design and operation) was formulated and conducted to discover main controlling factors which influence production. Firstly, wells were divided in three groups based on their current production rates. Wells in best group have good production in DST tests and higher production after stimulation. Wells in better group have no production in DST tests but obtaining good production after stimulation. Wells in bad group have no production in DST tests, yet very low production after stimulation. Then correlate well production with structure, reservoir property, geomechanics and natural fracture properties to reveal the key controlling factors. Further study was focused on combining multiple parameters to decipher productivity secret based on multi-domain evaluation results. Lastly it was found out that the well performance in this field is controlled by both Stress and NF, i.e. the angle (θ) between NF and the maximum horizontal stress. When θ is small, well productivity is good. Otherwise well productivity is poor. According to this new finding, different stimulation methods were chosen, designed and executed in the field.
Through integrated study on different levels, from core analysis to reservoir evaluation, the main factors controlling the tight gas field productivity were deciphered. Together with the understanding of the reservoir, the selection criteria for well stimulation were formulated with the intersection angleθ. After application of study results in stimulation design, gas production shows significant improvement: the average daily production rate increases 50% per well.
Experimental Investigation on Propagation Interferences of Staged Multi-Cluster Perforation Fractures in Tight Sandstone
Authors: Zhou Dawei , Zhang Guangqing , Liu Zhibin , Zhou Zaile 
Published: August 2016

Abstract
Currently, staged multi-cluster perforation fracturing was proved to be an efficient method to achieve the maximum stimulated reservoir volume in unconventional reservoir stimulation. However, an extensive work was conducted to study the influences of net fracturing pressure, fractures spacing and in-situ stresseses. However, the pore-pressure distribution, may affecting hydraulic fracture growth, was not well understood. Therefore experimental and numerical simulation are used to study the influence of pore-pressure distribution on sequential and simultaneous fracturing in tight sandstone.
In this paper, the experiments are divided into two categories, to investigate the interference of staged fracture propagations in porous sandstone subjected to true tri-axial stresses. Two independent fluid pumps are used to control the growth of two neighboring fractures. After the experiment, the specimens are sliced to analyze fracture paths. Then 3D fluid-solid coupling model is applied to simulate fracture propagation under the influence of pore-pressure distribution. Both experimental results and numerical modeling with pore pressure show attraction between the adjacent fractures, instread of repulsion in both sequential and simultaneous fracturing in experiments. More specifically, when the ratios of fracture spacing to fracture half-length are small, the fractures turn towards and coalesce with each other. And when the ratios of fracture spacing to fracture half-length are large, there is no obvious interference between the fractures. Consequently, among the parameters, other than net fracturing pressure, the fracture spacing and in-situ stresses, pore-pressure distribution plays a vital role on the fracture propagation, which leads to non-planar and asymmetric bi-wing fractures. The influences of pore pressure can attribute to shear failure of rocks, caused by reduced effective stress. Thus, increasing the perforation clusters interval can lower the possibility of deflection or coalescence of the multi-fractures, which promotes the performance of staged multi-cluster perforation hydraulic fracturing in tight sandstone.
Micromechanical Characterization of Fluid-Shale Interactions via Nanoindentation
Authors: Yang Zhenning , Wang Liming , Zhang Guoping , Ho Carlton 
Published: August 2016

Abstract
Preventation of shale formation damage by fracturing fluid-rock interactions plays an important role in well production performance and subsequent refracturing design. In this paper, the effect of converting typically hydrophilic fracture surface to hydrophobic ones on fluid-induced damage and softening is investigated. In particular, nanoindentation experiments were employed to characterize changes in the mechanical properties of shale samples with different surface treatments.
Shale samples were treated by octadecyltrimethoxysilane (OTMS) to convert the initially hydrophilic surfaces to hydrophobic ones, followed by inundation in water to allow for fluid-rock interactions. Nanoindentation testing was then conducted on the samples to characterize hardness, Young's modulus, and fracture toughness to examine the effect of fluid-rock interactions on shale mechanical properties and whether surface treatment can mitigate shale-softening. Its unique advantage is that the near-surface properties (but not the entire bulk sample) can be characterized, thus elucidating how water-rock interactions migrate from the surface to the interior of the rock.
Results obtained from nanoindentation testing were analyzed by statistical analysis and by a proposed clay matrix criterion. Different treatments lead to variable alterations to rock properties. The hardness and Young's modulus exhibit a reciprocal steady state trend at certain depths. Samples with hydrophobic surfaces exhibit a higher resistance to fluid-shale interactions, as reflected by a 40% higher hardness, a 25% higher Young's modulus, and a 35% higher fracture toughness, when compared with untreated shale samples. The untreated rock actually shows a 48% reduction in hardness, a 27% reduction in Young's modulus, and a 43% reduction in fracture toughness in the rock interior. This study also demonstrates that nanoindentation testing provides multiple advantages in characterizing the fracturing fluid-rock interactions at the micro/nano scale, since these interactions start from the rock surface and propagate to the interior without significantly involving the bulk rock. Nanoindentation testing is competent in characterizing micromechanically fluid-shale interactions and how surface treatment can mitigate the softening of shales.
Treatment Design Considerations for Effective Proppant Pillar Construction
Authors: Nelson Scott , Gomaa Ahmed M. , Hudson Harold , Brannon Harold 
Published: August 2016

Abstract
As an alternative to conventional proppant pack placement, propped pillar-fracturing promises more effective and conductive fractures by enabling hydrocarbons to flow through open channels. Recent experimental and numerical studies confirmed that viscous fingering phenomena can be used to develop a proppant pillar-fracture type placement: High-viscosity, proppant-laden fluid is placed, and then a low-viscosity clean fluid is pumped to carve pathways through the proppant-laden fluid in a dynamic, continuous process. However, the created channel pattern was found to be significantly dependent on fracture geometry and treatment design parameters such as injection rate, fluid pulsing time, and fluid viscosity ratio.
The objective of this study is to extend the numerical investigation and normalize it to develop a treatment design methodology for constructing proppant pillars throughout the created fracture. A computational fluid dynamics (CFD) model was constructed using commercial CFD software, simulating the flow of fluids inside the fracture and the resulting proppant pillar generation. The study focused on the effects of surface injection rate, pulsing time, and viscosity ratio between the two injected fluids, to develop correlations between all these parameters and the created fracture geometry.
Based on numerical results, the viscosity ratio chosen to achieve the proppant pillars allows for the use of conventional crosslinked fluid without the need for a hindered settling agent. The optimum channel pattern has small channel sizes, remains open under closure stress, creates more channels distributed throughout the entire fracture area, and maintains good communication between unpropped areas. A new dimensionless term, Dimensionless Stage Volume (VSD), is presented to describe the channel pattern inside the fracture. The settling of proppant occurs after the pumping of the job has ended, and prior to fracture closure, yielding wider pillar widths compared to current pillar-fracturing treatment techniques. A combination of conventional proppant and ultra-lightweight proppant can be continuously pumped as part of the treatment schedule. The application of lightweight buoyant proppant positioned within the created channels supports and braces against possible fracture closure between proppant pillars.
An Effective Model of Near-Well Complex Fracture Network After Hydraulic Fracturing
Authors: Li Junchao , Lei Zhendong 
Published: August 2016

Abstract
Hydraulic fracturing is an effective approach to bring economic productions for unconventional gas reservoirs. A numerical model is developed to model the complex fracture network after hydraulic fracturing. Particular treatments for full-tensor effects and fractures of different scales are integrated in the method to deliver fast evaluating the effect of hydraulic fracturing on recovery of unconventional gas reservoirs.
A discrete fracture model of the complex fracture network is firstly built up as the high-resolution reference model. Then numerical simulation grids are determined according to the fracture scales, fracture distribution and well locations. During numerical simulation, primary hydraulic fractures are treated explicit as the reference model, while relatively small-scale hydraulic fractures and natural fractures are upscaled into dual porosity grids by global upscaling procedures under multipoint flux approximation scheme. An integrated output least squares method, which aims to minimize the total bias of simulation results, is adopted to obtain the optimal transmissibility connection list of the simulation model.
An application case is designed to validate the proposed method. The results show that the proposed model can improve the computational efficiency for predicting the effect of hydraulic fracturing, and can maintain an equivalent numerical precision at the same time. This model can serve as a reliable tool for fast evaluating of different plans in hydraulic fracturing of unconventional gas reservoirs.
The Application of Numerical Simulation Stress Field in Shale Fracture Diagnostics
Authors: Wang Shize , Wu Zhaoliang , Liao Rugang , Xu Gang , Wan Xiaoping , Du Jinling , Liu Wei 
Published: August 2016

Abstract
The storage space of shale can be broadly divided into matrix pore and fracture, of which matrix pore mainly refers to the native micro holes and the secondary micro holes or microcracks formed through hydrocarbon generation by organic matter, clay mineral dehydration, as well as weathering, leaching and corrosion, and the formation of fracture mainly relates to the hydrocarbon generation by organic matter, layer pore pressure, disparity horizontal pressure, folds and faults, etc. Numerical simulation technology of regional stress field is the accurate simulation of stress and distortion of geologic body--mainly the simulation of yield limit and strength limit-based on regional tectonic study. In this paper, using numerical simulation technology of regional stress field and 3D seismic attribute interpretation technology and micro-seismic monitoring technology, we analyzed and predicted natural fracture growth and distribution in the study area to lay a foundation for the choice of "sweetzone" and the formulation of reservoir fracturing reform plan.