bluuebunny/crossref_metadata_2025_split huggingface dataset:
Multi-Phase Fluid-Loss Properties and Return Permeability of Energized Fracturing Fluids
Authors: Ribeiro Lionel H. , Sharma Mukul M. 
Published: January 2011

Abstract
With the growing interest in low-permeability gas plays, foam fracturing fluids are now well established as a viable alternative to traditional fracturing fluids. Present practices in energized fracturing treatments remain nonetheless rudimentary in comparison to other fracturing fluid technologies because of our limited understanding of multi-phase fluid- loss and phase behavior that occurs in these complex fluids. This paper assesses the fluid-loss benefits introduced by energizing the fracturing fluid to estimate when and why energized fluids may be suitable.
A new laboratory setup has been specifically designed and built for measuring the leak-off rates for both gas and liquid phases under dynamic fluid-loss conditions. This paper provides experimental leak-off results for linear guar gels and for N2- guar foam-based fracturing fluids under a wide range of fracturing conditions. In particular, the effects of the pressure drop, the rock permeability, the fluid shear rate, the polymer concentration, and the foam quality are investigated. Analysis of dynamic leak-off results provide an understanding of the complex mechanisms of viscous invasion and filter-cake formation occurring at the pore-scale.
This study presents data supporting the superior fluid-loss behavior of foams, which exhibit minor liquid invasion and limited damage. It also shows direct measurements of the ability of the gas component to leak-off into the invaded zone, thereby increasing the gas saturation around the fracture and enhancing the gas productivity during flowback. The conclusions not only confirm but add to the findings of McGowen & Vitthal (1996) for linear gels and the findings of Harris (1985) for nitrogen foams.
Better Injectivity Through Science: Case Histories of Stimulating Water Disposal Well Efficiency
Authors: Durey Daniel , Bell Charles , Weiss Stephanie 
Published: January 2011

Abstract
One downside of prolific oil and gas production is the often associated increase in produced water volumes. As hydrocarbon prices and production increase, so do water production and the need for efficient water disposal. This need plus increasing regulatory scrutiny and operators’ environmental stewardship goals have compelled the search for economic methods of safely maximizing - and maintaining - disposal well efficiency.
This paper will relate case histories of several salt-water disposal wells in northwestern Louisiana, in which the conventional remediation solution, matrix acid treatments, did not effectively remove near-wellbore damage. Instead, precision bypass fracs were designed to maximize injectivity without fracturing rock beyond the narrow zonal limits set by state regulators. The strict regulations required a precise, scientific approach to stimulation design and operations, including the use of fracture modeling, on-site diagnostics and radioactive tracers.
The paper will present regulatory issues, stimulation design process, operational highlights and post-stimulation results for some representative disposal wells. It will also describe improvements made at producing well locations to minimize future stimulation requirements. Finally, it will conclude with some recommended best practices for economical, safe, effective bypass frac design and operations in water disposal wells.
Hydraulic Fracture Stimulation Design Considerations and Production Analysis
Authors: Stegent Neil , Ingram Stephen , Callard Jeff 
Published: January 2011

Abstract
When the word "shale" is included in the name of a formation, a high-rate water frac is often instantly assumed to be the correct choice for hydraulic fracture treatment. This is because high-rate water fracs are the common treatment in the Barnett shale in northeast Texas, and that is the shale reservoir with which industry professionals are most familiar. When a new shale development, such as the Eagle Ford shale in south Texas, is discovered, engineering tends to take a back seat, and a high-rate water frac is often the initial treatment design chosen simply because that is what has been done in the Barnett. Reservoir understanding acquired from core analysis, geomechanical tests, formation evaluation, proppant-embedment testing, stress analysis, and other data are sometimes ignored in the design process.
This paper discusses the thought process that engineers are encouraged to follow when deciding what type of completion should be used to fracture stimulate a shale reservoir (water frac, hybrid, or conventional). Considerations, such as the type of hydrocarbon that is expected to be produced, fracture complexity of the reservoir, lithology and mineralogy of the rock, and other reservoir parameters, should be included as part of the completion design. To close the loop, the production also should be evaluated to make good engineering-design changes as the asset is developed. Quantifiable analysis of a stimulation treatment in a horizontal well can be a daunting task because of the complexity and lack of data. Production analyses for several stimulated wells are presented. This application can be directed toward any horizontal completion in low/ultra-low permeability reservoirs and can be performed in a timely manner. The immediate goal of this process is to determine a qualitative measurement of stimulation effectiveness; the eventual goal is a quantitative tool.
Hydraulic Fracture Crossing Natural Fracture at Non-orthogonal Angles, A Criterion, Its Validation and Applications
Authors: Gu H. , Weng X. , Lund J. , Mack M. , Ganguly U. , Suarez-Rivera R. 
Published: January 2011

Abstract
Hydraulic fracturing treatments have become an indispensable part of well completion in shale gas field development. Shale formations often contain natural fractures and complex hydraulic fracture networks may form during a treatment. The complex fracture network is strongly influenced by the interaction between the hydraulic fracture and the pre-existing natural fractures. A criterion has been developed to determine whether a fracture crosses a frictional interface (pre-existing fracture) at non-orthogonal angles. This criterion is an extension of the one for orthogonal crossing originally developed by Renshaw and Pollard (1995). The dependence of crossing on the intersection angle is shown quantitatively using the extended criterion. The fracture is more likely to turn and propagate along the interface than to cross it when the angle is less than 90°. The validation of the criterion using laboratory experiments for various angles is described and discussed. When applied to laboratory experiments, good agreement between the criterion and experiments is observed for a wide range of angles. The criterion can be used to determine whether hydraulic fractures cross natural fractures under particular field conditions, and it has been incorporated in a hydraulic fracture model that simulates hydraulic fracture propagation in a natural fractured formation.
Utilizing Fluid and Proppant Tracer Results to Analyze Multi-Fractured Well Flow Back in Shales: A Framework for Optimizing Fracture Design and Application
Authors: King George E. , Leonard Dick 
Published: January 2011

Abstract
Fluid and proppant tracers and other simple measurements in returning load water flow back can be very useful in helping to describe fracture development in shales; including such parameters as fracture complexity, frac conductivity, height growth, frac barrier effectiveness, well-to-well and frac-to-frac interference, water entry points and general fracturing execution. For most engineers, flow back ion charts have often had little relevance beyond estimating frac stage flow back activity; however, combining fluid tracer information with low-level gamma emitting proppant tracers, microseismic, simple salinity measurements and water return rate can help describe fracture and formation behaviors that lead to faster optimization of fracturing design and application. This paper will use fluid and proppant tracer results from over a hundred shale frac stages in horizontal wells along with other measurements of frac flow back and blend them with microseismic, frac pumping records, production logging and production results to build a framework for better analysis of frac flow back.
Redesigning Fracturing Fluids for Improving Reliability and Well Performance in Horizontal Tight Gas Shale Applications
Authors: Bell Charles E , Brannon Harold D. 
Published: January 2011

Abstract
Fracture stimulation is necessary in tight gas and shale formations to ensure commercial production volumes. Variations of slickwater are the predominant fluid used in shale stimulation because their low viscosity and relatively low costs. These stimulation treatments commonly use ceramic proppants or sand to create, develop and maintain the fracture network connectivity to the wellbore. Low viscosity fluids generate fractures of more narrow width and thereby, increased complexity of the created fracture network, which is thought to provide better stimulation of tight gas shales. However, proppant settling in low-viscosity fluid can reduce the chance of achieving optimal fracture conductivities. Friction reducers allow surface equipment to achieve high pump rates and fluid velocities that can overcome some proppant settling. High proppant concentrations during slickwater treatments tend to create settling and banking problems in surface equipment and in the horizontal wellbore. Conventional crosslink systems have been used to improve placement of the proppant by minimizing proppant settling. However, in addition to potential conductivity damage imparted by the conventional crosslinked fluids, the inherent high viscosity of such systems may significantly reduce the amount of desired fracture complexity created in the tight gas formations.
Recent advances in polymer refining offer the capability of pumping an instant-crosslink system with polymer loadings as low as 8 pptg. This ultra-low polymer crosslink system provides a surface viscosity that maintains effective proppant transport through the surface equipment, perforations, and into the near-wellbore area. Additionally, programmed viscosity degradation converts the fluid to a low viscosity within minutes of introduction to the reservoir to provide a desired complexity to the created fracture network. The low polymer loadings minimize polymer volumes introduced to the formation, and therefore formation damage.
This paper will detail the effects of new system's viscosity on proppant transport through the surface equipment and horizontal wellbore, and the development of a viscosity break profile that can deliver a low viscosity, near- Newtonian fluid that is ideal for developing the intricate fracture system to optimize production from tight gas formations.
Long Term Stability Of Proppants Exposed To Harsh Shale Reservoir Conditions
Authors: LaFollette Randy F. , Carman Paul S. 
Published: January 2011

Abstract
Laboratory experiments under reasonable Haynesville Shale reservoir temperature conditions have shown that an uncoated ceramic proppant and shale samples changed significantly in key physical properties. Proppant tensile strength was reduced significantly and Brinell Hardness of the shale was also reduced significantly from long-term exposure to broken fracturing fluid. The water chemistry of the fluid changed substantially during the entire 6 month time at temperature test period. It was concluded that the time dependency of these changes may have important implications for well drawdown practices for similar reservoirs, fracturing materials, and conditions. SPE 131782 presented an early progress report on these experiments, using single proppant crush, proppant type and a single fracturing fluid chemistry.
The purpose of this paper is to present the next progress report. New experiments have used both low and high-pH make-up water. Tests completed since the first report and including results from both coated and uncoated sand and different ceramic proppants will be reported. Changes in water chemistry from the laboratory experiments have been compared to long-term post-fracturing water chemistry changes in Haynesville Shale wells. Results show good agreement between the chemistries of the produced water and the water sampled from the laboratory tests.
Hydraulic Fracturing of Horizontal Wells: Issues and Insights
Authors: Daneshy Ali 
Published: January 2011

Abstract
The unparalleled spread and variety of completions in use by the industry have clouded the selection of suitable completion and best fracturing strategies for optimizing productivity of hydraulically fractured horizontal wells. There also exists a gap in our understanding of the mechanics of fracture initiation and extension in horizontal wells. This has resulted in uncertainty in our response to large variations observed within and between different fracturing stages in the same horizontal well, and in fact within the reservoir.
This paper is based on review of many horizontal well hydraulic fractures. It includes a discussion of multiple completion options for both open and cased holes. It shows that in open hole completions there is strong tendency for fractures to initially grow axially (longitudinally) before re-orienting to become perpendicular to the least in-situ principal stress. This can cause fracture extension across open-hole packers and possibility of randomly located transverse fractures (well orientation permitting). Infrequent screen-outs usually occur within the open hole section itself. There is evidence indicating that the sealing balls used for separating different fracturing stages may sometimes break during the treatment. This may prohibit fracturing all well segments, and may also interfere with production. In cases of open hole fractures created by hydrajetting techniques one of the issues is propensity to proppant flowback.
In cased hole completions the tendency for axial initiation and early growth still exists. One of the popular techniques is creation of multiple closely-spaced limited entry fractures within each isolated wellbore interval. Treatment data shows that many of these fractures soon join and coalesce towards a single fracture. Furthermore, proppant and fluid have different distributions between various perforations. The issues with techniques based on hydra-jetting include inadequate perforations, hardware problems, and tendency for proppant flowback.
Evaluation of After-Closure Analysis Techniques for Tight and Shale Gas Formations
Authors: Mohamed I. M. , Nasralla R. A. , Sayed M. A. , Marongiu-Porcu M. , Ehlig-Economides C. A. 
Published: January 2011

Abstract
Optimized hydraulic fracture design requires formation permeability as an input, but it is difficult to quantify in tight gas and shale gas reservoirs. After closure analysis (ACA) following a minifrac or fracture calibration test may offer a means to determine the formation permeability in cases for which both a formation test and a conventional pressure buildup test are impractical and/or unable to provide the permeability. However, ACA techniques use a variety of specialized plots, and there is a risk that apparent straight lines may lead to erroneous results.
This paper proposes a technique that provides a simple way to calculate formation permeability, initial reservoir pressure, fracture length, and closure pressure from a single specialized plot. The proposed technique is compared with the G-function method for the estimation of the closure pressure. In addition, it is compared with 3 ACA techniques (Benelkadi, Gu, and G-Function) used in the literature to calculate formation permeability for tight gas and shale gas wells.
Three field examples of pressure fall-off tests (in tight sand gas wells and shale gas well) are analyzed. The results show that the proposed technique provides a clear and rigorous analysis procedure for determination of permeability and other parameters required for the hydraulic fracture design. This proposed technique uses only a single plot comparing to the multiple plots required by the other techniques.
Evaluation of a High-Density Brine Viscosifier for Ultra-Deep Fracture Stimulation
Authors: Gupta D. V. , Carman Paul S. 
Published: January 2011

Abstract
With the oil and gas industry looking ever deeper for hydrocarbons, well control and completion have become important challenges to overcome. Ultra-deep wells usually have pressured or over-pressured formations and require heavyweight brines to control hydrostatic pressures. Completions that once used fresh water or sea water are no longer feasible due to the much higher pressure requirements, which surface treating equipment cannot sustain. Consequently, the industry has started using heavyweight brines as a base for fracturing fluids. However, the practice is limited by the polymer and the base brine. The most commonly used systems employ NaBr, usually in the range of 11.0 to 12.5 ppg, with a modified guar, buffer, crosslinker and other additives. The systems are finicky and hard to break, and the NaBr brines along with calcium and zinc brines, have increased in cost, prompting a search for alternative, inexpensive solutions.
A newly developed system will viscosity any brine from 11.0 to 19.2 ppg with only gellant and breaker added to the base brine. No buffer, crosslinker or other additives are necessary, which greatly enhances operational efficiency, especially offshore. The unique polymer system creates an association with the salt solution to generate viscosity. The system can be used with lower-cost brine blends such as NaCl/NaBr, CaCl2 and CaBr2. The resulting fluid is very elastic and has excellent proppant transport characteristics. The system can be broken efficiently to achieve good regain conductivity. This paper will present the chemistry and results of complete laboratory testing to evaluate the fluid for fracturing applications.
Fracturing Fluid for Extreme Temperature Conditions is Just as Easy as the Rest
Authors: Gupta D. V. , Carman Paul 
Published: January 2011

Abstract
As exploration goes deeper, most conventional methods have to be modified or completely re-engineered to hold up to these extreme conditions. Fracturing fluids are no exception to these changes. Fluids have evolved rapidly to adjust to an ever changing market. The trick is to make them as easy as possible to deliver on location. There have been several attempts at developing new high temperature fluids that will give good stability and deliver the fracture properties desired. Most of these to date require special handling and have operational difficulties.
A new high temperature synthetic low-pH crosslinked fluid system has been developed to avoid these pitfalls. The system employs a synthetic co-polymer in an environmentally compliant oil-based emulsion that hydrates very rapidly with excellent fluid rheology properties. Proppant pack regain conductivity using encapsulated oxidizers has also shown very good cleanup at these temperatures. The system uses exceedingly low polymer concentrations (18 to 40 pptg) compared to others (60 to 100 pptg) at temperatures from 350 to over 450°F. The fluid can also be energized with nitrogen or carbon dioxide or foamed if needed. Operationally, fracturing with this fluid can be performed with conventional equipment without any modifications. The paper will present the chemistry and technology of this new fluid including rheology and cleanup data.
This new technology has the potential to change the manner in which ultrahigh-temperature wells are completed.
The Unexpected Rheological Behavior of Borate-Crosslinked Gels
Authors: England K. W. , Parris M. D. 
Published: January 2011

Abstract
Fracturing fluid testing methodology and equipment has evolved, as have industry-accepted standards for testing. These standards have undergone a number of revisions over the years and were published first as a recommended practice under the American Petroleum Institute (API RP-39) and subsequently under the International Standards Organization as ISO-13503-1. These standards define the rotor/bob geometry (for a concentric-cylinder viscometer), shear-rate, temperature control and other parameters selected to determine the fluid performance under in situ conditions. Little focus was given to the pressure applied to the fluid, other than to ensure that it would not boil under test conditions. This lack of emphasis on pressure is completely understandable as condensed matter (solids and liquids) typically have a limited response to the pressures experienced during hydraulic fracturing operations.
It has been discovered that pumping pressures encountered during hydraulic fracturing treatments can materially reduce the viscosity of a borate-crosslinked fluid. The loss in viscosity, depending on fluid formulation, temperature, and pressure can range from negligible to complete resulting in a fluid with the viscosity of an uncrosslinked polymer solution (linear gel). This phenomenon has been studied using high-pressure rheometry and high-pressure nuclear magnetic resonance (NMR).
This paper presents the results of recent testing of a variety of aqueous-based fracturing fluid systems under a range of pressures typical of hydraulic fracturing treatments. Detailed results for various borate-crosslinked fluids commonly commercially available will be presented as well as non-typical systems.
A New Correlation of Acid Fracture Conductivity Subject to Closure Stress
Authors: Deng J. , Mou Jianye , Hill A. D. , Zhu D. 
Published: January 2011

Abstract
The conductivity of an acid-etched fracture depends strongly on void spaces and channels along the fracture resulting from uneven acid etching of the fracture walls. In this study, we modeled the deformation of the rough fracture surfaces acidized in heterogeneous formations based on the synthetic permeability distributions and developed a new correlation to calculate the acid-etched fracture conductivity.
In our previous work, we modeled the dissolution of the fracture surfaces in formations having small-scale heterogeneities in permeability. The characterization of the correlated permeability fields of rock includes the average permeability, normalized correlation lengths in both horizontal and vertical directions, and normalized standard deviation. These statistical parameters have a significant influence on the fracture etching profiles obtained from the model. Beginning with this fracture width distribution, we have modeled the deformation of the fracture surfaces as closure stress is applied to the fracture. The elastic properties of the rock, such as the Young’s modulus and the Poisson’s ratio, have effects on the size of the spaces remaining open after fracture closure. After the model yields the width profile under closure stress, the overall conductivity of the fracture is then obtained by numerically modeling the flow through this heterogeneous system.
In this paper, we introduce our models and investigate the effects of both permeability and mineralogy distributions, and rock elastic properties on the overall conductivity of an acid etched fracture. A new acid-fracture conductivity correlation is developed based on many numerical experiments.