bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Method for the Design and Selection of Premium / Woven Sand Screens
Authors: Mondal Somnath , Sharma Mukul M. , Hodge Richard M. , Chanpura Rajesh A. , Parlar Mehmet , Ayoub Joseph A. 
Published: October 2011

Abstract
Woven metal mesh sand screens, commonly known as premium screens, have been extensively used by the industry. Sand retention testing is often done to evaluate the performance of these screens and establish empirical guidelines for screen size selection. However, these tests are tedious and the results are prone to artifacts and have been used, at best, to correlate trends in sand retention performance with select sand size distribution parameters. A new method incorporating results from numerical modeling in addition to experimental data is presented to estimate the mass and size distribution of the produced solids through premium screens. This method provides a fast, reliable correlation to estimate sand production through premium mesh screens when the size distribution of the formation sand is known.
This paper presents results from a wide range of sand retention experiments. In these tests the mass of sand produced and its size distribution over time are measured. Results of three-dimensional, discrete element computer simulations of woven screen geometry placed in contact with granular sand packs of ~100, 000 particles are also presented. Based on both the simulations and the experiments a new method for screen selection is presented. This method is based on a correlation that allows us to use the entire sand size distribution of the formation sand and estimate the mass and size distribution of the produced sand. The method is validated by comparisons with experimental data.
A new method and new correlations for estimating the mass and size distribution of produced solids through premium screens is presented. Key differences in sand retention mechanisms between premium and wire-wrapped screens have been identified. The method uses the entire formation sand size distribution (as opposed to a single design point) and has been validated with laboratory tests. The method also helps in screening anomalous test results.
The Effects of Fracturing Fluids on Shale Rock Mechanical Properties and Proppant Embedment
Authors: Akrad Ola , Miskimins Jennifer , Prasad Manika 
Published: October 2011

Abstract
The development of shale reservoirs has grown significantly in the past few decades, spurred by evolving technologies in horizontal drilling and hydraulic fracturing. The productivity of shale reservoirs is highly dependent on the design of the hydraulic fracturing treatment. In order to successfully design the treatment, a good understanding of the shale mechanical properties is necessary.
Some mechanical properties, such as Young's modulus, can change after the rock has been exposed to the hydraulic fracturing fluids, causing weakening of the rock frame. The weakening of the rock has the potential to increase proppant embedment into the fracture face, resulting in reduced conductivity. This reduction in conductivity can, in turn, determine whether or not production of the reservoir will be economically feasible, as shale rocks are characterized by their ultra-low permeability, and conductivity between the reservoir and wellbore is critical. Thus, shale reservoirs are associated with economic risk; careful engineering practices; and a better understanding of how the mechanical properties of these rocks can change are crucial to reduce this risk.
This paper discusses various laboratory tests conducted on shale samples from the Bakken, Barnett, Eagle Ford, and Haynesville formations in order to understand the changes in shale mechanical properties, as they are exposed to fracturing fluids, and how these changes can affect the proppant embedment process. Nanoindentation technology was used to determine changes of Young's modulus with the application of fracturing fluid over time and under high temperature (300 °F) as well as room temperature. Mineralogy, porosity, and total organic content were determined for the various samples to correlate them to any changes of mechanical properties. The last part of the experiments consisted of applying proppants to the shale samples under uniaxial stress and observing embedment using scanning acoustic microscope.
The results of this study show that maximum reduction of Young's modulus occurs under high temperature and in samples containing high carbonate contents. This reduction in Young's modulus occurs in "soft" minerals as well as the "hard" rock-forming minerals. This reduction of modulus can cause the effective fracture conductivity to decrease significantly.
Transportation and Interaction of Nano and Micro Size Metal Particles Injected to Improve Thermal Recovery of Heavy-Oil
Authors: Hamedi Shokrlu Y. , Babadagli T. 
Published: October 2011

Abstract
Studies on the application of transition metal particles for heavy oil or bitumen up-grading were conducted in the absence of a porous medium, mainly measuring the characteristics of heavy-oil in reaction with metal ions at surface conditions. Dynamic tests on porous media are needed to clarify the injection possibility of the metal particles and their effect on in-situ recovery and up-grading heavy oil. Injection of metal particles may deteriorate the recovery process by damaging porous media due to attractive forces such as van der Waals and electrostatic forces between particles and porous rock. A better understanding of these forces and their importance in the retention of particles is required.
In this paper, the injectivity and transport of nickel particles was studied. The injected suspension was stabilized using Xanthan gum polymer and ultrasonication. The effect of the solution pH, which controls the magnitude of the repulsive electrostatic forces, was clarified. Stabilization of the metal particles suspension was studied at different pH values through zeta potential measurements. Also, the zeta potential of the recovered suspensions was studied to confirm the stability of the suspension during travel through the porous medium. Depending on the size and type, particles carry different charges. Therefore, the stabilization pH and dispersant concentration was different from one sample to another. The results of the injectivity tests confirmed the lower retention of nanoparticles in comparison with micron-sized particles.
A steam simulation process was applied in the presence and absence of metal particles, and heavy-oil recoveries were monitored. Higher recovery was achieved when nickel nanoparticles were used. The changes in asphaltene content and the viscosity of the heavy oil confirm the catalytic effect of the nickel nanoparticles on the in-situ upgrading of heavy-oil.
Extending Production Petrophysics Applications in Monitoring Complex Recovery Mechanisms
Authors: Zett A. , Webster M. , Seccombe J. , Colbert C. , Ansari R. , Chace D. 
Published: October 2011

Abstract
Due to variable reservoir properties, displacement mechanisms and well access issues, cased hole reservoir surveillance for fluid saturation is often challenging. Traditional methods such as capture cross section (sigma) and carbon/oxygen logging are limited in these environments and new techniques are often needed to successfully monitor fluid changes.
This paper discusses the application of two new pulsed neutron based techniques that utilize capture and inelastic gamma ray data acquired with a three detector pulsed neutron instrument. Measurements are combined with theoretically modeled tool responses for different fluids (water, oil and natural gas or carbon dioxide) to determine saturations. Inelastic and capture ratio measurements from the first and third detectors are used because they exhibit higher formation sensitivity than conventional two-detector instruments. These ratios respond differently to changes in oil/gas densities, compositions and formation water salinities, and these differential responses can be used simultaneously to solve for a three-phase saturation solution.
This paper presents results from two mature fields in Alaska. The first example is a three-phase saturation analysis in a light oil reservoir with pressures close to bubble point where traditional sigma and carbon/oxygen logging has been unsuccessful. The new technique located bypassed oil which was produced by adding perforations and confirmed by running production logs. In a second example, the problem was the surveillance of gas cap injection water with seasonal source water salinity variations injecting into a low porosity conglomeratic zone. Trapped gas saturations derived using the new technique were consistent with lab derived core flood measurements. This new generation neutron data has been used to help reduce the range of uncertainty in water salinity and improve the estimation of water saturation within the gas cap even in the low porosity conglomerates.
The new techniques provide an effective solution in environments where conventional pulsed neutron measurements have high uncertainty. Future applications of this measurement in similar areas include the monitoring of reservoirs with complex lithologies where the calibration points are difficult to define and the distinction between gas condensate and dry gas have been problematic for traditional techniques.
Improved Reservoir Characterization through Estimation of Velocity Anisotropy in Shales
Authors: Prasad Tushar , Vines Robert 
Published: October 2011

Abstract
Shales make up most of the sedimentary basins and overlie many hydrocarbon bearing reservoirs. To obtain reliable information on reservoir properties from seismic data, a good understanding of the wave propagation through shales is required. The velocity in shales depends on the direction of wave propagation, as shales are intrinsically anisotropic due to the preferred alignment of clay platelets. This inherent velocity anisotropy in shales must be taken into account for seismic imaging and inversion, seismic-to-well ties, and amplitude variation with offset (AVO) analysis.
Sonic logs provide formation velocities for generating synthetic seismograms, which are subsequently used in the above mentioned seismic analyses. Due to intrinsic anisotropy of shales, the sonic logs in deviated wells can differ from the vertical well response by 30% or more. This needs to be taken into account for accurate seismic analyses. Several methodologies have been developed for estimation of shale anisotropy from deviated-well sonic logs. This paper presents a method to estimate Thomsen's anisotropy parameters from sonic logs as well as density logs in deviated wells.
Three different cases are presented, encompassing exploration, appraisal & development, and production scenarios. Thomsen's anisotropy parameters are estimated using both sonic logs and density logs in deviated wells. When the well deviation is 30 degrees or more, the impact of anisotropy is significant. Accounting for anisotropy provides better confidence in the subsequent seismic analyses. For example, correct VP/VS ratio as an input to AVO analysis ensures improved prediction of reservoir fluid and lithology. Similarly, the synthetic seismograms calculated using anisotropy-corrected velocity logs result in better seismic-to-well ties and seismic inversion.
Field examples illustrate the importance of shale anisotropy quantification for improved reservoir characterization. The use of both sonic as well as density logs to quantify anisotropy has the advantage of taking wave propagation direction as well as compaction into account, and may provide a better local calibration in terms of porosity and burial history.
A Semi-analytical Approach for Estimating Optimal Solvent Use in Solvent Aided SAGD Process
Authors: Gupta Subodh , Gittins Simon 
Published: October 2011

Abstract
SAGD process is widely used to recover heavy oil and bitumen from formations where no other recovery method is proven to be economical. It is an energy intensive process and due to economic and environmental reasons, solvents as additives to the injected steam are currently being explored to reduce energy and emissions intensity of SAGD. The Solvent Aided Process (SAP), tested in field and described in literature, is one such attempt.
In SAP, a small amount of hydrocarbon solvent is introduced as an additive to the injected steam. The viscosity of the oil thus is also reduced due to solvent dilution in addition to heating. SAP can significantly improve the energy efficiency of SAGD, thus reducing the heat requirement as shown in field trials discussed elsewhere. However on the use of right amount of solvent that can result in best overall performance, there is very little discussion in the literature. Due to the high cost of such solvents there is incentive to optimize their use in SAGD. Recently a couple of authors have attempted to address the subject by, for example, using arbitrary time-dependent schemes of solvent injections and assessing their impact on results or treating the internal reservoir dynamics as black-box and using optimization methods such as genetic algorithm to estimate optimal amount of solvent. While these approaches orient us to the problem in a context specific manner, it is believed a generalized treatment to estimate optimal use of solvent requires a mechanism-based understanding.
The approach presented in this paper aims to estimate the optimal solvent in SAGD context. It breaks down the process in its relevant theoretical elements, i.e., a sequential frontal advance with progressive front renewal on account of gravity drainage. This in turn facilitates investigation of a relationship between phase behavior of the solvent, its amount, and the performance of the recovery process. The results are discussed for a few light-alkane solvents.
Better optimal solvent estimates promise to shed light on the supply logistics of these solvents, improve the overall economics and reduce the energy requirements of the heavy oil and bitumen recovery projects.
An Effective Model of Pipe Friction Prediction from Laboratory Characterization to Field Applications for Friction Reducers
Authors: Zhou Jia , Sun Hong , Qu Qi , Bai Baojun 
Published: October 2011

Abstract
Slickwater fracturing technology has been widely used for well stimulation because it is inexpensive and causes relatively little formation damage. Friction reducers are always employed in the slickwater fracturing fluid system due to the high friction pressures resulting from the high rates of fluid injection. Polyacrylamide-based polymer is the most common friction reducer in the industry. Many papers have reported the results of tests on friction reducers in water-based fluids in laboratory-scale straight and coiled tubes, but few have attempted to address the gap between laboratory and field operation data. For example, laboratory tests using conventional fluid rheological parameters do not accurately predict friction reduction when applied to the large pipes used in field operations. Friction reducers’ evaluation using full-scale flow loop testing with tube sizes comparable to those used in field operations are typically expensive and require large volumes of fluids, making them impractical.
This paper describes an attempt to address the gap between laboratory characterizations and field operations, so called "diameter effect". It reports a study of two common friction reducers tested in a laboratory setup. It introduces a new effective model based on fluid velocity profile to reliably predict field friction reduction from laboratory results. The correlation between laboratory and field data is validated by comparing predictions with actual field data from a large number of slickwater fracturing treatments over a wide range of pumping rates and well tube sizes. The study demonstrates that correct lab testing parameters are essential for reliably using laboratory results to predict the effectiveness and performance of friction reducers under field conditions.
Improved Sand Management Strategy: Testing of Sand Monitors under Controlled Conditions
Authors: Emiliani C. N. , Lejon K. , Lindén M. , Engene J. , Kvernvold O. , Packman C. , Clarke D. , Haugsdal T. 
Published: October 2011

Abstract
Sand production has been a constraint to obtain maximized production rates for a number of years for several Statoil fields in the North Sea, due to issues related to: erosion potential not always easy to assess; safe operations: too many uncertainties related to increased sand production; and limited process handling capacity.
Statoil has implemented the Acceptable Sand Rate (ASR), developed together with DNV, as a company strategy for increasing production rates by tolerating sand production within certain limits of maximum allowable sand volume, and maximum allowable erosion in the flow lines and the process system. Although these efforts have resulted in increased production, there is still a way to go to fully utilize the production potential. A key factor with respect to effective sand management is the collaboration and continuous communication among operators and suppliers, and the confidence and methodical approach that engineers and sand monitors’ users should employ supported by a cross disciplinary effort. This paper will present the work carried out jointly by the operator and the suppliers through extensive lab work on the sand monitoring systems available today. The aim of the work is to explore the influence of piping geometry, sand characteristics and fluid/operational conditions on the sand monitors, in a controlled environment, in order to improve their implementation according to the ASR strategy. Instruments, test conditions, CFD analysis, results and conclusions will be described for both acoustic and erosion based monitoring devices.
Lattice Boltzmann Simulation Of Non-Darcy Flow In Stochastically Generated 2D Porous Media Geometries
Authors: Newman M. S. , Yin X. 
Published: October 2011

Abstract
It is important to consider the additional pressure drops associated with non-Darcy flows in the near well bore region of conventional gas reservoirs and in propped hydraulic fractures. These pressure drops are usually described by the Forchheimer equation in which the deviation from the Darcy's law is proportional to the inertial resistance factor (β-factor). While the β-factor is regarded as a property of the porous media, detailed study on the effect of pore geometry has not been done. Many previous experiments and simulations were based on idealized systems such as packings of spheres. In this study, the effect of geometry was studied using a combination of lattice Boltzmann simulations and stochastically constructed 2D porous media models designed to simulate the geometric complexity of reservoir rocks. Based on the data obtained from about 1100 simulations run in 55 model geometries within a porosity range of 8-35%, a dimensionally consistent correlation for the β-factor was established. The effect of geometry on the transition to non-Darcy flow and on the β-factor was evident. It was discovered that the contrast between pore throat and pore body triggers an early transition to non-Darcy flows. Following a quick transition where the correction to the Darcy's law was cubic in velocity, the flows entered the Forchheimer regime where the β-factor increased with decreasing porosity or increasing level of heterogeneity. Inspection of flow patterns revealed both steady vortices and onset of turbulent motions in the Forchheimer regime. The latter correlated well with published point-of-transitions. In developing the correlation for the β-factor, we show that it is necessary to include two distinctive characteristic lengths to account for the effect of pore-scale heterogeneity. This finding reflects the simple fact that it is the contrast between pore bodies and throats that dictates the flow properties of many porous media. In this study, we have used the square root of the permeability and the fluid-solid contact length as the two characteristic lengths, a practical choice when direct measurement of the microscopic length scales is not available. This method can be used in the future to correlate three-dimensional numerical and experimental data.
Fullfield Heavy Oil Conversion from Cold to Hot Production; Challenges and Solutions
Authors: Jansen F. E. , Curtis A. , Mejia-Cana L. V. , Ramsdal J. , Selboe J. O. 
Published: October 2011

Abstract
With an increasing interest for extra heavy oil (EHO) extraction, a number of heavy oil fields will initially be produced using a cold production scheme, while at a later stage thermal production in the form of steam injection can be introduced to enhance the recovery.
Such a fullfield conversion from cold to hot production has so far only been performed to a limited extent, hence the experience and understanding of the various challenges with such a task is limited. While much work has been carried out on both cold and hot production of extra heavy oil as stand alone processes, little has been published around the procedure of converting from cold to hot production.
This conversion contains a number of pitfalls detrimental to a successful field development. In an EHO cold to hot conversion scheme, several choices will have to be made with respect to well positioning, completion options, timing and scale of the conversion. Investment decisions in surface equipment, handling and cost of water and gas for steam generation are also important considerations. All of these designs and decisions affect the success and profitability of the conversion scheme.
One of the basic challenges with modeling cold to hot conversion is the difference in scale required. The thermal simulation of a hot production scheme requires a very fine grid to capture the fine scale processes, while for full field simulation one needs a much coarser grid to be able to obtain a manageable model both in size and simulation time. The high number of producers and injectors required on a fullfield scale adds to the complexity of the problem, making recovery, production profile and optimal number of wells highly uncertain. A simplified translation to fullfield conditions of these parameters from sector models or spreadsheets, can introduce erroneous results and conclusions.
To assure the best field performance over its lifetime, these issues need to be considered already in the initial field design. Based on the work performed, several interesting observations have been made regarding how to optimize field performance.