bluuebunny/crossref_metadata_2025_split huggingface dataset:
Extrapolation of Laboratory Proppant Placement Behavior to the Field in Slickwater Fracturing Applications
Authors: Woodworth T. R. , Miskimins J. L. 
Published: December 2007

Abstract
Low-viscosity slickwater treatments are a popular hydraulic fracturing technique in low permeability reservoirs. Slickwater treatments can provide adequate conductivity in tight gas sand operations at comparatively low costs, and wells treated with low-viscosity slickwater often produce better results than those treated with cross-linked fluids in low permeability situations. Theoretically, proppant transport is poor in low-viscosity slickwater type fluids. Improving the understanding of proppant transport capabilities of slickwater would be beneficial to many operators if the cost or performance were not endangered. Improved proppant transport would result in longer propped fracture half-lengths and more favorable conductivity.
Laboratory experiments performed by STIM-LAB, Inc.'s Proppant Consortium show proppant falls from suspension and builds a proppant mound before any form of proppant transport takes place. Clean fluid stages pumped between sand-laden stages were shown to erode proppant from the proppant mound. These results formed the basis for the development of power and bi-power laws to describe the transport. These laws and the results of the laboratory experiments were used to perform sensitivity analysis to determine the relative effects of fluid viscosity, fluid density, pump rate, proppant diameter, proppant density, proppant concentration, and fracture width on slickwater treatments in the field.
Using the power and bi-power laws, the resulting sensitivity analysis, and the laboratory observations, experimental slickwater schedules were designed and field tested. A total of five experimental slickwater fracturing treatments were performed. Production data from each experimental slickwater treatment and well were compared to offset data to determine any possible effects from improved proppant transport. Production results from the field trials, including both initial production (IP) rates and early cumulative production totals, indicate significant improvement when compared to offset wells.
Numerical Simulation of Hydraulic Fracturing in the Viscosity Dominated Regime
Authors: Bunger A. P. , Detournay E. , Garagash D. I. , Clarkson U. , Peirce A. P. 
Published: December 2007

Abstract
Most hydraulic fracturing treatments are in the viscosity-dominated regime. Hence, fracture growth does not depend on the rock toughness and it can be shown that the fracture aperture w near the fracture front, when viewed at the scale of the whole fracture, is not characterized by the classical square root behavior predicted by linear elastic fracture mechanics w ∼ s1/2, where s is the distance from the tip. Instead, the asymptotic tip aperture that reflects the predominance of viscous dissipation is of the form w ∼ s2/3, under conditions of large efficiency and small fluid lag. After demonstrating the intimate connection between the tip aperture and the fracture propagation regime, we report the results of hydraulic fracturing laboratory experiments in PMMA and glass blocks that employ a novel optical technique to measure the fracture opening. These experiments provide incontrovertible evidence that the power law index, characterizing the fracture aperture near the tip, depends on the propagation regime in accordance with theoretical findings. Finally, we demonstrate that a coarsely-meshed planar hydraulic fracture simulator can produce accurate results relative to benchmark solutions provided that the appropriate tip behavior is embedded in the algorithm. Through theoretical, experimental, and computational considerations, these results make it clear that advances in the accuracy and efficiency of fracture simulators critically depend on a sophisticated treatment of the near-tip aperture that goes beyond basic linear elastic fracture considerations.
Case Studies of Propped Refracture Reorientation in the Daqing Oil Field
Authors: Wang S. G. , Zhang G. L. , He X. Q. , Liu X. , Hou F. , Cui T. X. 
Published: December 2007

Abstract
This paper presents case studies of re-fracture treatments and reorientation measurement results by surface tiltmeter mapping in the Daqing oilfield. All the four treatments in this study included a novel design technique of pumping paraffin balls approximately half way through the propped treatment in an attempt to initiate fracture growth in a different orientation or through different perforation intervals. Tiltmeter mapping results indicated that fracture reorientation occurred for the majority of the re-fracture treatments studied.
A Singular Evolutive Interpolated Kalman Filter for Rapid Uncertainty Quantification
Authors: Liang Baosheng , Alpak Faruk O. , Sepehrnoori Kamy , Delshad Mojdeh 
Published: December 2007

AbstractInherent data and model uncertainties render the history-matching inverse problem extremely non-unique. Therefore, a reliable uncertainty quantification framework for predicting reservoir dynamic performance requires multiple reservoir models that match field production data. It has been previously demonstrated that the ensemble Kalman filter technique can be used for this purpose. In this technique, an ensemble of reservoir models is evolved by means of a stochastic nonlinear filtering procedure to agree with the observed production data. An efficient variant of the ensemble Kalman filter, namely, Singular Evolutive Interpolated Kalman Filter (SEIKF) is applied to the multi-model history-matching problem in this work. This novel technique operates in three steps: resampling, forecasting, and assimilation. Unlike the ensemble Kalman filter, where the members of the model ensemble are operated by forecasting and assimilation, in SEIKF, the members of the model ensemble are selected in the main orthogonal directions of a functional space described by an approximation to the error-covariance matrix. This enhanced sampling strategy, embedded into the resampling step, improves the filter stability and delivers rapid convergence.SEIKF is applied to a three-dimensional proof-of-concept waterflooding case where reservoir permeability is calibrated to production data. Accuracy and convergence of history match as well as the uncertainty of dynamic predictions yielded by the final model ensemble are used as criteria to evaluate the performance of SEIKF. The outcome of the proof-of-concept studies quantitatively demonstrates that SEIKF exhibits rapid convergence in the domain of model parameters. In terms of accuracy and uncertainty reduction, SEIKF performs comparable to a conventional ensemble Kalman filter. SEIKF promises a rapid and reliable framework for history matching and naturally lends itself to uncertainty quantification.
Prediction of Long-Term Proppant Flowback in Weak Rocks
Authors: Aidagulov G. R. , Thiercelin J. , Nikolaevskiy V. N. , Kapustyanskiy S. M. , Zhilenkov A. G. 
Published: December 2007

Abstract
Proppant flowback is an extremely important phenomenon in hydraulic fracturing technology and may cause severe problems for well completion. Various models have been developed to predict the onset of proppant flowback but the physics of the phenomenon has still to be understood to predict the amount of proppant flowback during the life of a well. In particular, determining whether the proppant flowback will stop after a few days of production or will continue at a given rate during the well's life is a key issue when selecting an appropriate completion method. The development of a model allowing a quantitative prediction of this process is therefore a very vital task. In this paper we present a quantitative model to predict proppant flowback. The model is based on treating both the proppant pack and the reservoir as poroelastoplastic media. It allows for solid production from the proppant pack but also from the formation itself in case the fracture was created in a very weak reservoir formation.
According to this model, the fluid and rock skeleton are considered as two interpenetrating continua. The Mohr- Coulomb yield criterion with the non-associated plasticity rule written in terms of the Terzaghi effective stress is used to describe the flow of a solid matrix connected with the pore pressure gradient.
The influence of proppant properties, rock properties, in-situ stress, fracture width, and flow rate on proppant flowback is studied to determine the controlling parameters. It is shown that when a severe proppant flowback problem occurs, the closure stress around the wellbore is significantly altered. In some cases, the fracture width at the wellbore is decreased leading to the cessation of solid production, while in others continuous production is maintained. It is shown that the selection of proppant properties is an efficient way to control flowback, but obviously the requirement in terms of strength depends on the downhole conditions.
Shear Dilation Diagnostics: A New Approach for Evaluating Tight Gas Stimulation Treatments
Authors: Chipperfield S. T. , Wong J. R. , Warner D. S. , Cipolla C. L. , Mayerhofer M. J. , Lolon E. P. , Warpinski Norman Raymond 
Published: December 2007

Abstract
Many tight gas reservoirs require fracture stimulation to achieve commercial outcomes. These reservoirs can often be characterized geologically and geomechanically by high deviatoric stresses and hard, naturally fractured rock. Stimulation treatments in such reservoirs may create complex fracture networks from a combination of shear and tensile failures. Water fracs can be used where shear failure is anticipated to dominate. However, in these environments few practical modeling tools exist to determine [1] the level of permeability enhancement, [2] the degree of permeability retainment during drawdown and [3] the Stimulated Rock Volume (SRV). This paper seeks to provide the engineer with a suite of tools capable of achieving these goals.
This paper presents a dual porosity, pressure dependent permeability reservoir simulation model that was devised to honor shear failure mechanisms [also called shear dilation] using basic geological characterization. The assumptions of this model and the pragmatic selection of first order effects are discussed. Using the results of this simulation model, three families of diagnostic tools are presented.
The first category is that of Treatment Diagnostics (TD) which include bottomhole pressure evaluation, injectivity and fall-off analysis. The second approach is called Seismic Based Reservoir Characterization (SBRC), which uses the microseismic to determine the SRV as well as provide estimates of the initial and stimulated fracture network properties. The third category is Post Treatment Diagnostics (PTD), which incorporates the evaluation of pressure drawdown characteristics.
Finally, this paper compares these individual approaches and provides a workflow to evaluate data on future wells.
Production Data Analysis for Commingled Multilayer Gas Reservoirs—Graphical Aides for Flow Regime Identification and History Matching
Authors: Spivey John P. 
Published: December 2007

Abstract
Most of the major unconventional gas plays in the U.S. have multiple productive intervals. Wells are completed with multiple fracture treatments, and are produced commingled.
An earlier paper1 described a single-well, multilayer, analytical reservoir simulator* for estimating individual layer properties in multilayer unconventional gas reservoirs by automatic history matching production and spinner survey data simultaneously. The present paper describes several interactive graphical aides that greatly facilitate the history matching process when used in conjunction with the analytical, multilayer reservoir simulator. These graphical tools include an allocation graph and layer and cumulative production log graphs. These graphs allow the engineer to quickly review the quality of the match at any point during the history matching process.
Use of these graphical tools has improved the history matching workflow to the point that a complete history match of a well with 20 frac stages, two years of daily production, and three spinner surveys can be performed in as little as four to six hours, from construction of the initial data set through completion of the final match.
Evaluation of the Elliptical Flow Period for Hydraulically-Fractured Wells in Tight Gas Sands—Theoretical Aspects and Practical Considerations
Authors: Amini S. , Ilk D. , Blasingame T. A. 
Published: December 2007

Abstract
It has been long established from well testing concepts that an elliptical flow pattern exists in hydraulically-fractured wells producing from low permeability (&lt;0.01 md) and ultra-low (&lt;0.001 md) formations (often referred to as "tight gas" or "shale gas" sands). Conceptually, the elliptical flow period is a transitional flow regime that occurs between the end of bilinear and/or formation linear flow and the onset of pseudo-radial flow. In a practical sense, the elliptical flow regime can (and does) dominate the well performance for very low permeability reservoir systems.
Elliptical flow (as with pseudo-radial flow) represents a time period when the reservoir properties begin to dominate the reservoir performance. Moreover, the duration of the elliptical flow period may last for many months, perhaps even years, depending on the reservoir and hydraulic fracture properties. Consequently, understanding the elliptical flow period and its impact on well performance is critical for the optimal development of a tight gas sand reservoir.
This paper presents a series of decline type-curves for a system consisting of a hydraulic fracture at the center of an elliptical reservoir. The curves are generated from the pressure solution obtained using an analytical method. The curves are generated for different values of the fracture conductivity and as a function of the elliptical boundary characteristic parameter (ξ0).
For the low permeability cases where the elliptical flow period dominates, the elliptical boundary characteristic parameter (ξ0) is a useful parameter for establishing the optimum well spacing and the optimal design for the drainage aspect ratio. We note that the ξ0-parameter essentially reduces the optimization process for tight gas reservoirs to a single parameter that should yield the optimum configuration for drainage and production performance. Obviously the fracture conductivity is also a major factor, as is the reservoir permeability and the fracture half-length — but the ξ0-para-meter is the key to recovery and performance in systems dominated by elliptical flow behavior.
Liquids Phase Holdup and Separation Characteristics as a Function of Well Inclination and Flowrate
Authors: Awal Mohammad R. , Razzak Shaikh A. , Al-Majed Abdulaziz A. , Al-Yousef Hasan Y. , Zughbi Habib D. 
Published: December 2007

Abstract
The maturing Middle Eastern oil fields with natural aquifer support or water injection can pose a challenging produced water handling and disposal issues. The increased water-oil ratio also presents productivity problems: many wells will die prematurely due to increased water holdup. The produced water management cost @US$ 0.50—1.00 per barrel involving millions of barrels of water (even at a modest WOR of 50% from current 30–35%) will be in billions due to the high daily oil production rate envisaged. In this paper, we focus on various aspects of downhole oil-water separation, which we believe will lessen the cost significantly. The downhole water separation technology developed and applied in the western hemisphere cannot be directly applied here because of the orders of magnitude higher production rates per well.
Lacking a production flow-loop facility in the region with full-scale production equipment, we use an industry-standard commercial computational fluid dynamics (CFD) simulation tool to investigate inline oil and water separation characteristics under downhole conditions. Specifically, we investigate the startling sensitivity of well inclination in the 80–100 degrees range. We show that it is crucial to control the well inclination within a tight regime to achieve effective and manageable liquids separation in near horizontal wells. We also show that the liquids phase separation in these wells are sensitive to the gross liquids flow rate.
The CFD simulation study reported in this paper will lead to new technology development that can be used to achieve more effective well completion design in near horizontal wells drilled specifically to obtain downhole oil-water separation. The success of such innovative oil-water separation will save many producing wells from dying prematurely and save millions of dollars in produced water handling and disposal.
Field Based Criteria For The Design of Safe Mud Weight Window
Authors: Mohiuddin M. A. , Khan K. , Abdulraheem A. , Al-Majed A. , Aurifullah V. 
Published: December 2007

Abstract
Field based parameters like initial mud weight used for drilling, mud weight increment and problems per well were used to analyze wellbore instability, identify different instability mechanisms and design safe mud weight window for drilling horizontal wells. These parameters were used first on the drilling data of vertical wells to develop the procedure for the analysis of wellbore instability and identify the mechanism of instability. The developed procedure was then applied to the drilling data of directional wells to show the dependence of mud weight on the inclination and azimuth of the well. Finally, the procedure was applied to horizontal wells data along with the concept of critical washouts to infer the safe mud weight window. The safe mud weight window is validated on another set of drilling data showing 90% success rate.
Estimating the Amount of free Sand in the Yielded Zone around Vertical and Horizontal Oil Wells
Authors: Al-Awad Musaed N. J. , Al-Ahaidib Talal Y. 
Published: December 2007

Abstract
Predicting sand production accurately is a difficult task; many techniques have been previously investigated such as production history, mechanical property analysis using electrical log data, laboratory testing and computer modeling.
In this study, the mechanism of sand production problem in an oil reservoir producing medium oil (30° API) from a weak sandstone formation was investigated. An analytical model is elaborated based on linear-poroelastic solution of stress state around circular openings as well as Mohr-Coulomb failure criterion and Darcy's equations for fluid flow through porous media in vertical and horizontal wellbores.
In this study, a new important factor necessary for the estimation of the mount of free sand generated between sheared planes caused by the fluid drawdown was introduced. This factor is called sand production capability factor. Sand capability factor was evaluated experimentally for the studied reservoir.
Observations of sand production in the studied oil reservoir were utilized to tune and verify the model used in this study. For open-hole completion, it was found that; free sand ready to move into the wellbore is inversely proportional to radial distance. Furthermore, free sand ready for production from the yielded zone around vertical wells is higher than that in the case of horizontal wells. The predicted free sand in all studied cases is in accordance with field observations.
Selection of borehole and perforation orientation (in case of perforated casing completion) with respect to the maximum horizontal principal in-situ stress has a great effect in reducing the potential free sand amounts ready to move into the wellbore along with the producing reservoir fluids. Horizontal wellbores oriented at 45° produce minimum sand compared with other horizontal orientations for the studied reservoir. Similar effect is found for perforations phased at zero angular position.
Experimental Assessment of Bacterial Ability to Tackle the Wax Problem in the Crude Industry
Authors: Paitakhti Oskouei S. J. , Roostaazad R. , Ghotbi S. , Sadeghazad A. 
Published: December 2007

Abstract
Mesophilic bacterial specie was isolated from an active Iranian oil well and together with another available bacterial strain was evaluated in tackling the well known wax problem. Both of the strains proved to grow on the crude as the sole carbon source while supported by inorganic salts, phosphorous and nitrogen sources. The growth phases had a lag phase of less than 1 day and lasted more than 1 week before entering the stationary phases. The optimum oxygen requirements of the bacteria were not large. The isolated bacterium was successful to decrease pH from 7 to 5.5, the initial surface tension of 65 to as low as 55 dyne/cm and the wax and asphaltene content as much as 27.8% and 10.6% respectively. These effects are expected to have a positive effect on the cloud and pour points, deposition tendency of the crude and/or emulsification of deposited wax in a sweeping medium such as injected water.
New Strategic Method to Tune Equation-of-State for Compositional Simulation
Authors: Al-Meshari Ali A. , McCain William D. 
Published: December 2007

Abstract
Since the plus fraction of reservoir fluids has some uncertainty in its molecular weight and critical properties, equation-of-state, EOS, are generally not predictive without tuning its parameters to match experimental data. Tuning of the EOS is found to be the best method for improving the predictions of compositional reservoir simulators.
The proposed strategy for tuning EOS consists of seven steps: (1) split the laboratory plus fraction to single carbon number groups, SCN, usually up to SCN 44; the last component will be C45+, (2) use set of correlations to calculate the critical properties and acentric factor for each SCN group, (3) match the saturation pressure at reservoir temperature by altering the measured value of the molecular weight of the plus fraction using the extended composition, (4) group SCN groups to multiple carbon number groups, MCN, (5) assign critical properties and acentric factor for each MCN group, (6) rematch the saturation pressure at reservoir temperature using the grouped composition, and (7) match the volumetric data by regressing on volume shift parameters of all components in grouped composition.
This paper shows an accurate method to split the plus fraction to SCN groups. The most accurate set of correlations to calculate the critical properties and acentric factor for each SCN group that will result in a small adjustment for the molecular weight of the plus fraction when saturation pressure is matched using the extended composition. The proposed strategy groups the extended composition to eight pseudocomponents. The binary interaction coefficients between hydrocarbons and between hydrocarbons and non-hydrocarbons are set to zero which dramatically reduces the simulation time.
The strategy proposed in this paper for tuning EOS to match experimental data has been tested for a wide range of C7+ mole% (4 – 25) which covers gas condensate and volatile oil samples. The scope of this paper is to come up with an accurate and systematic technique for tuning an EOS for use in compositional simulation.