bluuebunny/crossref_metadata_2025 huggingface dataset:
Development of Seawater-Based Fracturing Fluid for High-Temperature Wells
Authors: Vo L. K. , Biyani M. V. , Cortez J.. , Hoeman K..
Published: August 2016

The development of a high-temperature seawater-based fracturing fluid has received much attention because it offers a solution to fresh water shortages; however, the rheological properties suffer significantly as a result of interactions between dissolved ions with fluid components. Various strategies have been investigated to address this challenge, including seawater treatments that ultimately remove the highly soluble and insoluble ionic moieties to yield a fracturing fluid with reliable rheological characteristics.

Most polymer-based fracturing fluids have limited salt tolerance. Interactions between the polymer and divalent cations in seawater inhibit proper polymer hydration, thus preventing generation of an elastic polymer network and potentially affecting the crosslinking mechanism. In this study, concentrations of critical ions in seawater were reduced using a reliable seawater treatment. This treatment allowed a reliable fluid at higher temperatures and also considerably reduced the scaling tendency of the fluid. The fluid presented herein, designed in the treated seawater, yields a stable elastic polymer network when used in conjunction with stabilizing additives and is capable of effectively delivering proppant down hole.

This newly developed formulation uses a combination of instant and delayed crosslinkers and additional stabilizing additives required at optimum concentrations to yield a stable fluid system in the treated seawater. At high temperatures, the addition of typical ion sequestration agents failed to eliminate the negative interaction between dissolved ions and fluid stability, thus requiring water pre-treatment. The fluid system exhibits reliable rheological properties and yields a clean broken fluid for excellent proppant pack cleanup in high total dissolved solids (TDS) waters up to 350°F. Typical guar-based fracturing fluids require a high pH (greater than 10) to maintain rheological stability at high temperatures. The fracturing fluid presented herein was developed at pH 9 in treated seawater and maintained its elasticity and viscosity over a long period of time at temperatures up to 350°F. An added benefit of controlling the pH and not surpassing pH 9.5 was also revealed—scale control.

This study discusses the development of a new seawater-based fracturing fluid for use in high-temperature wells. This can result in a paradigm shift in source water use for hydraulic fracturing.
The Evolution and Control of Fluid Phase During Liquid CO2 Fracturing
Authors: Meng Siwei , Liu He , Xu Jianguo , Duan Yongwei , Yang Qinghai , Yao Zixiu
Published: August 2016

Liquid CO2 fracturing is a novel stimulation technology, which helps realize multiple objectives such as conservation of water, sequestration of greenhouse gases and enhancement of single-well productivity and ultimate recovery. During operations, CO2 flows through storage tank, booster pump, blender, fracturing pump, and eventually into wellbore and production zone, generating a changing temperature and pressure distribution. CO2‘s phase state, density and viscosity properties change consequently, which influence significantly the reliability and stimulation effect.

In a liquid CO2 fracturing field test for tight oil, temperature and pressure sensors are positioned at 12 critical nodes (including booster pump, blender, fracturing pump, wellhead and bottom hole) to monitor CO2 fluid. To ensure the reliability, CO2 is required to maintain in liquid state both on the surface and subsurface. Inlet, inside and outlet pressure of the blender should be concerned, because the blender utilizes non-mechanical pump, which requires sufficient motive flow to draw proppants into the main pipe, while the pressure difference directly impacts the flow rate of motive flow.

The field test is successfully implemented with satisfactory result, 21 m3 proppants are added into the formation. The main conclusions are as follow. (1) In low-pressure fluid feeding stage, partial CO2 is gasified, which influences the stability of fluid feeding; In future a buffer vessel will be placed between storage tanks and booster pumps, which will provide adjustment for phase control; And a heat exchanger may help by further reduce the temperature of CO2.(2) Pressure difference among inlet, inside and outlet pressure of blender fluctuates during the whole process, with the probable reason of two additional static mixers, which create system pressure drop. (3) The temperature of CO2 is very low in low-pressure stage, and the pipes are frosted; When pumping pressure reaches 38MPa, the temperature gradually exceeds 0°C, and the pipes are defrosted.

Phase evolution during liquid CO2 fracturing has been identified, and phase control method has been determined. This helps improvethe stability of fluid feeding and sand adding, and enhances the success ratio and stimulation result of fracturing.
Modeling of Injection Induced Seismic Events
Authors: Zhang Xi , Jeffrey Robert G. , Wu Bisheng , Zhang Guangqing
Published: August 2016

Using a BEM-based hydraulic fracture model and the Coulomb frictional law, the generation of slip and shear rupturing produced by fluid injection is investigated. A wide range of factors can contribute to injection-induced seismicity. In addition to injection rate, fluid viscosity and existing permeability, several other factors are considered in this paper to determine their effects on slip development during continuous fluid injection and during shut-in. These factors include dilatant strengthening, slip weakening of frictional coefficients, structural complexities along a rupturing path like jogs and branches and the application of far-field wave-form stresses. The numerical method is summarized and the theoretical formulation of the above physical processes associated with generation of seismic events is provided. The numerical results show a rich and complex local slip rate change during extension of the slip zone. Under fluid injection, the slip can first produce a seismic event either caused by rapidly increasing pressure or by abrupt slip initiation, and then slows. When the permeability is large enough, the slip pattern manifests itself as long-term slow slip period coupled with aseismic slip transients. The long-duration and low-magnitude seismic events are associated with the slipping state in the conditionally stable regime, in which fluid pressure is marginally equal to a value required to produce slip using the effective stress and the static frictional strength. A small perturbation in the fluid pressure caused by any of the above factors can stop and/or generate relatively faster slip rates. The slip continues varying with time after shut-in in the presence of the above influencing factors. The slow slip on a fault, which is difficult to detect by seismology, could be a significant process in dissipating elastic strain energy during hydraulic fracturing stimulations. In addition, the model can capture a tendency of the slip rate to become significantly large. The results demonstrate the importance of fracture and fault permeability enhancement on variations of fluid pressure and slip rates.
Thermal-Stress Induced Fracture Propagation by Cold Fluid - An Improved Hydraulic Fracturing Treatment for Unconventional Gas Reservoirs
Authors: Song Huifang , Liang Zhirong , Chen Zhixi , Gholizadeh Doonechaly Nima , Arns Ji-Youn , S. Rahman Sheik
Published: August 2016

Unconventional gas reservoirs (shale gas, tight gas and coal bed methane) constitute a large percentage of natural gas supply. Hydraulic fracturing is commonly used to break-up rock matrix and connect natural fractures and cleats to create gas flow pathways. Application of hydraulic fracturing, however, poses several problems including extremely low matrix permeability and poor connectivity between matrix and fractures. Several studies have been made in field and in laboratory to open and interconnect these natural fractures and cleat system with cold fluid, results of which are found to be promising. In this paper we present a parametric design analysis as to the application of thermal stress (due to cold fluid injection) induced hydraulic fracture treatment.

Propagation of natural fractures and cleats surrounding the induced hydraulic fracture by thermal induced stress is investigated in hydro-thermo-mechanical (THM) framework both numerically and experimentally to quantify the effect of thermal shock. Increase in fracture (natural fractures and cleats) aperture and propagation is modelled by cohesive zone method. Numerical results were validated by injecting cold liquid in 1 in diameter coal sample and changes in permeability were recorded. During the same time, the changes in aperture and length of cleat and fractures respectively were monitored by μ-CT.

Numerical results show that as the cooling front due to invasion of cold fluid moves into the matrix, it facilitates initiation of cracks in planes of weakness and/ or causes the cleats and natural fractures to open and propagate some distance away from the hydraulic fracture surface. This phenomenon is more pronounced around crack tips due to severe thermal straining. It was also observed that SIF and J-integral of cracks are much higher than that without thermal effect.

Thermal stress induced cleats and natural fracture propagation surrounding the treatment area extends the reach of the hydraulic fracture which otherwise could not have been connected. In this paper we present a quantitative analysis of the effect of thermal stress on fracture/ cleat propagation behaviour so that an improved understanding is gained with regard to the application of low temperature fracturing.
A Comprehensive Evaluation of Well Completion and Production Performance in Bakken Shale Using Data-Driven Approaches
Authors: Wang Shuhua , Chen Shengnan
Published: August 2016

The Bakken unconventional resource in Williston Basin is becoming an important component of hydrocarbon sources in North America. Although advanced horizontal drilling and multi-stage stimulation techniques being successful to exploit Bakken formations, appropriate completion and stimulation designs are crucial to maximize the well productivity and oil recovery of the shale or tight reservoirs. Data-driven approaches, such as deep neural network modeling and global sensitivity analysis, are promising methods to evaluate hidden correlations between multi-stage hydraulic fracturing strategies and well productions.

In this study, a total of 2919 wells including 2780 multi-stage hydraulically fractured horizontal wells and 139 vertical wells in the Bakken formation were collected and analyzed using a deep learning method and Sobol's sensitivity analysis. 18 features of a single horizontal well were extracted from the raw data resources. These features contain five aspects: well location and geometry, Bakken formation thickness, hydraulic fracture characterization, fracturing fluid, and proppant. 6 months' and 18 months' cumulative production were utilized to characterize the after-stimulation performance of horizontal wells. In the deep learning model, one-hot encoding method was used to deal with the categorical data. Xavier initialization, dropout technique, Batch Normalization, Adadelta optimizer were applied to develop the reliable deep neural network. Moreover, k-fold cross validation approach was used to evaluate the prediction ability and robustness of the models. Finally, the importance of each parameter was studied using the Sobol's sensitivity analysis.

Deep learning neural networks were firstly and successfully developed to predict the oil production of hydraulically fractured horizontal wells. The overall performance of deep network models is acceptable with a low mean squared error between estimated and measured oil production. The configuration type of networks has little effect on the performance of deep network models. While the number of layers and neurons in each layer have a significant effect on the performance of models. The best number of layers ranges from 4 to 7, and best number of neurons in each layer is between 100 and 200. Sobol's sensitivity analysis indicates that the average proppant placed per stage is the most important parameter contributing to ~ 35% of both the 6 months' and 18 months' cumulative oil production variability. Moreover, the interaction effects among parameters should be considered during the hydraulic fracturing design.

Results from this work can be used to optimize multi-stage hydraulic fracturing design for new Bakken wells. The proposed deep learning method and sensitivity analysis provide a potential workflow to evaluate well after-stimulation performance for multi-stage fractured horizontal wells and can be integrated into reservoir decision-making routines.
Production Logging of Shale Gas Well in China
Authors: Wei Pang , Dejia Di , Jun Mao , Tongyi Zhang , Ying He , Shuang Ai
Published: August 2016

China is the first country achieving shale gas breakthrough outside the North America. Fuling shale gas play is one of the most successful shale gas reservoirs by far in China. However, production loggings of shale gas wells illustrate that only about one third to one half of hydraulic fractures produces. Meanwhile, the productive fractures contribute differently to the production rate. Therefore, production logging technology is needed to evaluate the production status and contribution per stage or cluster, and get clear understanding of post-fracturing performance.

The paper generalized the difficulties and challenges for production logging taking the geology and well condition into consideration in Fuling shale gas play in China. These challenges include snubbing operation, production logging tools selection, tools conveying, unclean wellbore and complex flow regime in horizontal wellbore.

Aiming at solving the above the difficulties, one design of coiled tubing conveyed combination of conventional tools with single sensor and array tools with multiple sensors is formed. The array tools are used to diagnose fluid phase and measure gas/liquid holdup, thus data from single sensor tools and multiple-sensor array tools measurements can be combined to enhance the quality of the interpretation results. By comparison, the coiled tubing is more suitable for conveying the downhole tools in deep well with long horizontal wells. The Appropriate coiled tubing diameter is chosen and the coiled tubing passing ability in the horizontal lateral is simulated. The characteristics of array testing tools produced by Schlumberger and Sondex are analyzed. Since the array tools have the potential risks of being blocked or even damaged by fragments of bridge plugs, therefore, the borehole cleaning technique is considered. By statistics of wellhead pressure of shale gas wells in Fuling shale play, the BOP should be with pressure capacity over 50 MPa.

One case well in Fuling shale gas play shows that it is feasible to use coiled tubing conveyed array tools for production logging in shale gas well. The testing data interpretation results demonstrate the reliability of data interpretation method and the significance of production logging. For the case well, one half (6 stages out of 11 stages) fractures produce gas and the other half contribute nothing. The productive fractures also present different performance and the most predominant fracture contribute 36.47% of the total production. By production logging, not only fracture contribution to total production rate can be obtained, the flow regime and dynamic liquid level can also be determined. The production logging can be helpful for downhole fluid dynamic analysis and production optimization, and it may partly help the design of horizontal laterals and fractures scenarios.
Understanding Production Mechanism to Optimise Well Stimulation by Production Analysis in Keshen HPHT and Natural Fractured Tight Gas Reservoir
Authors: Yang Xiangtong , Huang Yongjie , Liu Ju , Xian Chenggang , Qiu Kaibin , Teng Qi , Gu Xiao , Zhao Meng , Pan Yuanwei , Wang Nan
Published: August 2016

The main pay of the Keshen gas field is a tight sand formation with very low porosity (2% to 7%) and permeability (0.001md-0.1md). Due to the ultra-deep formation depth and superior high reservoir pressure (greater than 116 MPa) and temperatures (above 160°C), the well construction and field development costs are very high. Therefore, stimulation treatments is essential for achieving sufficiently high production rate and the basis for justifying the costs. Natural fractures (NF) are developed in the reservoir with high heterogeneity which leads to complex production mechanism due to interaction between matrix and NFs, and causes difficulties on stimulation optimization.

To better understand the reservoir and optimize the well stimulation, the matrix properties, natural fracture, geomechanical data and stimulation data has been reviewed along with production data. Massive production history matching work has been done to evaluate the NFs. Other dynamic data like the well testing data and pressure data also reviewed to help understand NFs development in the full field scal. Production analysis was conducted to link the rock properties, NFs and wells' performance, and provided full understanding of production controlling factor in this reservoir. The post production analysis helped to understand the efficiency of stimulation. The production behavior for different stimulation strategy also have been illustrated by the simulation models to investigate the impaction on the stimualtion optimization strategy by the interaction between matrix and NFs.

The study provided a good understanding of the production mechanism in this kind of natural fractured reservoir and NF's impact on the stimulation efficiency. The heterogeneity of NF results in very different production mechanism given similar matrix petrophysical behavior. Based on production mechanism, each well requires a customized stimulation to maximize the production potential.

This study presented a case study for evaluating the production mechanism and highlighted the importance on evaluating the production mechanism on optimizing the stimulation for the naturally fractured tight reservoir.
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

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

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

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

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

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

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

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

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

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.
Application of Injection Well Fracturing in Extra Low-Permeability Oilfields
Authors: Jinfang Wang , Xingfan Zheng , Zhengmao Wang , Changbing Tian , Lei Xu , Xiaocui Gao
Published: August 2016

For the oil reservoirs with permeability less than 10×10-3μm2, the recovery rate is unsatisfactory because of poor reserve abundance, low pressure, low injection rate and high initial water saturation. This paper discusses the necessity and rationality of injection well fracturing, and optimizes the well spacing and fracture length of the production and injection well in extra low-permeability oilfields. The production wells are usually fractured for higher yield, however, injection wells are rarely fractured.

Mass data from field practice are analyzed in this paper. Changqing, Daqing and Jilin oilfield have all witnessed the journey of square inverted nine-spot well pattern, diamond shaped inverted nine-spot well pattern, square five-spot well pattern, rectangular well pattern, and linear injection pattern. The sweep efficiency and water flow direction are confirmed by core data in lab from 9 infill wells in a square inverted nine-spot well group in Changqing oilfield. Good agreement is obtained with field observations and lab. Using oil reservoir engineering method and numerical simulation with the Non-Darcy flow, this paper describes the optimization well pattern with injection and production wells fracturing.

After water flooding in the conventional areal well pattern, the injection water will flow toward the direction of the maximum principle stress, and finally forms the linear water injection, resulting in the low oil recovery due to the heterogeneous lateral water flooding. After a near 30-year water flooding development, the core data from 9 infill wells have proved the vertical sweep efficiency achieved only 50%, while the plane sweep efficiency 60%. Both water injection rate and oil production decrease with the increase of water cut. However, as water injection channel is formed with injection well fracturing, lateral water flood will displace homogeneously from the row of water wells to the row of oil wells. The injection wells fracturing increase the perforation and the injecting efficiency. Through the optimization of wells and the fracture length with the numerical simulation, an effective displacement pressure system is established for extra low-permeability oilfields. Compared with the adjacent area, Zhaozhou oilfield pilot tests were carried out according to the simulation studies and have achieved encouraging results in Daqing oilfield.

The novelty of injection well fracturing is in the ability to improve the injection efficiency and displace homogeneously toward the channel designed. The higher injecting efficiency is, the less injectors, well spacing density, and cost will be required, which properly serves the situation of low oil price.
Development and Application of a Recyclable Fluid for Sulige Tight Gas Fracturing
Authors: Huaqiang Shi , Xianwen Li , Li Ding , Yajuan Wang , Xiaolin Qiu , Ningjun Li
Published: August 2016

The pay zone of Sulige gas field is the most typical tight sandstone rservior in China. In recent years, multi-stage completion practices of vertiacal and horizontal wells brought about significant enhancement of single well production rate and economic benefit and caused a sharp increase of water consumption as well. Currently guar-based polymers are largely used in fracturing operations in Sulige gas wells. The system exhibit good rheological properties on one hand, and it can not meet the requirement of water saving, environmental protection and factory fracturing mode on the other due to its tendency to degrade, complex disposal and high cost. As a response, a low-cost recyclable fracturing fluid is developed and tried for the gas field.

A polyacrylamide polymer with surface activity is synthesized based on the consideration of reservoir characteristics, requirements in fracturing and well pad situation. The polymer and alkyl sulfonate surfactant additive formed a reversible structure in water by the action between hydrogen bonds and molecular chains. The fluid provides a good viscoelastic behavior and can meet the needs of fracturing treatment. It can be broken upon contact with formation fluid and rock minerals without destroying the molecular structure of the polymer. The flowback fluid can regain the viscoelasticity and be reused after simple settling and adding in proper dosage of the polymer. Lab experiment shows that the novel fluid has good temperature/shear resistance and excellent proppant transport capability. It is also easy to be cleaned up without leaving residue. Moreover, the performance of the recycled fracturing fluid can reach the level of that of prepared with fresh water. From 2014 to 2015, the recyclable fluid has been applied successfully in 230 wells in Sulige with a total volume of approximate 1,000,000 m3. The recovered flowback fluid is 400,000 m3, of which 380,000 m3 was reused. The recycling rate is as high as 95%. The fluid can meet the needs for continuous-mixing and low friction during treatment. The flowback fluid is also easier and less costly to be recycled in comparasion to guar gel fracs. These advantages promise its wide adaptability.
Maximizing Productivity with Ultra-Lightweight Proppant in Unconventional Wells: Simulations and Field Cases
Authors: Han Jianhang , Pirogov Alexander , Li Chunlou , Hurt Robert , Sookprasong Andy , Min Kim Jeong
Published: August 2016

Proppants are placed in fractures to provide highly conductive paths for hydrocarbons to flow from the reservoir to the wellbore. Hydraulic fracturing technology is constantly improving to achieve better production performance. Ultra-lightweight (ULW) proppants are one of the technologies introduced to improve fracturing effectiveness. Compared to sand, ULW proppants can be carried farther and distributed more evenly within fractures, resulting in more propped fracture area. This paper evaluates the impact of ULW proppants on production performance in tight reservoirs and examines characteristics of formations where ULW proppants are most beneficial.

To explore the advantages of ULW, hydraulic fracture models are developed. These models help in understanding the fracture geometric properties. This information is then incorporated into reservoir production models to evaluate the impact on production performance. Fractures using ULW proppants and the resulting well productivity are compared to those using sand. No technology provides a solution for all situations, and neither do ULW proppants. To better understand if ULW proppants bring the most benefit for production performance, data-mining techniques were used to identify ULW proppant field applications.

Results showed that ULW proppants had better vertical distribution within the fractures than sand (sand had a tendency to settle to the lower part of fractures, leaving the upper part unpropped). In a thick reservoir formation with insufficient vertical conductivity, fractures created by ULW proppants connected larger volumes of rock, leading to higher well productivity and increased EUR.

This study discusses the benefits that ULW proppants can bring to unconventional producers and identifies potential candidate formations where ULW proppant may be very effective. Field cases are included to show the benefits of ULW and the circumstances where they can bring the most value.