bluuebunny/crossref_metadata_2025_split huggingface dataset:
Role of Dispersion in Injectivity Impairment: Mathematical and Laboratory Study
Authors: Altoé F. J. E. , Bedrikovetsky P. , Siqueira A. G. , Souza A. L. , Shecaira F. S. 
Published: December 2007

Abstract
Severe injectivity decline during the injection of sea/produced water is a serious problem in offshore waterfloodings. The permeability impairment occurs due to capture of particles from injected water by the rock. The reliable modelling-based prediction of this decline is important for the injected-water-treatment design, for injected water management (injection of sea- or produced water, their combinations, water filtering etc.).
Particle transport in porous media is determined by advective flow of carrier water and by hydrodynamic dispersion in micro-heterogeneous media. Thus, the particle flux is the sum of advective and dispersive fluxes. Transport of particles in porous media is described by an advection-diffusion equation and by a kinetic equation of particle capture. Conventional models for deep bed filtration take into account hydrodynamic particle dispersion in the mass balance equation but do not consider the effect of dispersive flux on retention kinetics.
In the present study, a model for deep bed filtration taking into account particle hydrodynamic dispersion in both the mass balance and retention kinetics equations is proposed. Analytical solutions are obtained for flows in infinite and semi-infinite reservoirs and in finite porous columns. The physical interpretation for the steady-state flows described by the proposed and the traditional models favours the former.
Comparative matching of experimental data on particle transport in porous columns by the two models is performed for two sets of laboratory data.
Effect of Stress Concentration Factors due to Corrosion on Production Tubing Design
Authors: Sun Kai , Samuel Robello , Guo Boyun 
Published: December 2007

AbstractWith the increase in operating costs, as well as the need to withstand the cyclic swing of the oil prices, there is a growing demand for cost effective production operations. Challenges associated with extreme depth, pressures and temperatures, where corrosion is a problem, translate to additional problems due to tubing burst, collapse and tension. Tubings subjected to corrosion suffer strength deterioration. This becomes even more detrimental when coupled with cyclic loading. Failure of tubings could lead to disastrous consequences and the loss of well. If tubings were not designed with consideration of corrosion effects, it may result in well control operations also. This paper studies the effects of corrosion and examines the alterations proposed to the conventional tubing design. The objective is to adapt to the new criterion for deep water and ultra deep high-temperature high-pressure production wells. Stress concentration caused by corrosion cavity plays a key factor in the tubing design under a corrosive environment. The failure analysis of the model is based on the pitting corrosion. A method and revised criteria have been proposed to predict the threshold pressure for a derated tubing strength. Approximated analytical formulae have been developed for semi-spherical cavities, shallow surface cavities and deep spherical cavities. The effects of stress concentration factor on tubing strength are analyzed. Solutions are presented in the form of plots that can easily be used by the production engineers. In the paper, quantification of the method is analyzed with a practical tubing design example.
Analisis of Oil-Water Flow Tests in Horizontal, Hilly-Terrain, and Vertical Pipes
Authors: Abduvayt P. , Manabe R. , Watanabe T. , Arihara N. 
Published: December 2007

Abstract
The flow pattern, pressure drop and water holdup were measured for oil-water flow in horizontal, hilly-terrain (± 0.5° and ± 3°) and vertical pipelines at a temperature of about 35 ± 5 °C and a pressure of about 245 kPa using the large-scale multiphase flow-test facility of Japan Oil, Gas and Metals National Corporation (JOGMEC). Test lines of 4.19 inch (106.4 mm) ID and 120 m total length were utilized which included a 40 m horizontal or hilly-terrain and a 10 m vertical test sections sequentially connected. The flow pattern was determined by visual observation with video recordings, and a flow pattern map was made for each condition.
New flow patterns were identified for horizontal and hilly-terrain flow, such as oil flow in a snake-like shape at top of pipe at high rate of water flow, and water flow at bottom of pipe at high rate of oil flow.
New holdup and pressure drop data are presented for each flow condition. The flow rate and inclination angle influences holdup and pressure drop behaviors. In vertical flow, when the oil superficial velocity exceeds a certain value, the pressure drop decreases exponentially as the superficial oil velocity increases.
Slippage between the phases was analyzed using the measured water holdup plotted against the input water cut with inlet oil flow rate as parameters. It was found that the slippage changed significant with slightly changes in inclination angle.
This paper provides new experimental data of flow pattern, water holdup and pressure drop measured particularly at horizontal, hilly-terrain and vertical conditions with large-diameter pipes. These are the indispensable information of developing reliable prediction models for oil-water two-phase and gas-oil-water three-phase flow in pipelines.
The Stress Response of Permeability
Authors: Worthington Paul F. 
Published: December 2007

Abstract
The response of intergranular permeability to applied hydrostatic stress is quantified through third-order polynomial fits to data from three loosely-to-moderately consolidated sandstone reservoirs from the same geological province. The derivatives of the fitted polynomials allow diverse permeability vs. stress behaviors to be identified and grouped. This grouping is quantified using composite stress-response parameters based on the polynomial regression coefficients, most notably their root mean square. This composite parameter shows a sufficiently good correspondence to Leverett's equivalent circular pore diameter Lp to define exclusive "stress facies" in terms of ranges of Lp in these formations. A permeability reduction factor from ambient conditions to effective reservoir stress is determined for each stress facies as a basis for correcting conventional core measurements. Although the results are formation- and stress-facies-specific, the approach has a general validity and can be adopted for any appropriate permeability vs. stress function. Principal benefits include better reservoir characterization and a sharper description of the change in permeability with stress as a basis for improved simulation models for development planning.
Partial Probabilistic Addition: A Practical Approach for Aggregating Gas Resources
Authors: Delfiner Pierre , Barrier Robert 
Published: December 2007

AbstractThe portfolio of gas sources to supply an LNG project may involve many diverse fields, each with its range of uncertainty and degree of maturity. For project sanction it is necessary to aggregate the reserves/resources of all these fields into project-level representative numbers such as 1P/2P/3P or P90/P50/P10.Arithmetic addition of all low estimates (1P or P90) and all high estimates (3P or P10) is known to overstate the range of uncertainty. On the other hand, independent probabilistic addition tends to produce unrealistically narrow ranges. The correct answer would be obtained by using correlated addition, but this requires the estimation of all correlations between field resource estimates.This paper presents a simplified and pragmatic approach, partial probabilistic addition. A hierarchy of "resource containers" is defined from individual reservoirs to total project level, and resources are aggregated from bottom up using either arithmetic or probabilistic addition, whichever is more appropriate. This amounts to setting weak correlations to 0 and strong correlations to 1. Expert opinion is solicited only about the strength of dependencies, rather than being asked to specify elusive correlation coefficients.The validity of the approach is investigated by applying partial probabilistic addition to a synthetic portfolio of fields with the same lognormal size distribution. The study indicates the feasibility of estimating a global P90 with a controlled error, whereas for a P10 the error can become quite large. The method is then discussed using a real LNG case study.Partial probabilistic addition is a practical method. It is easy to understand and to explain. It can be summarized in a single table where a color code indicates for each cell how its value was calculated. These features facilitate technical interchange and QC, which are key to reducing as much as possible the degree of arbitrariness inherent in the modeling of dependencies.
Mapping Reservoir Fabric, Pressure Compartments and Natural Fracture Patterns Using Azimuthal Seismic Velocity
Authors: Parney Robert , Jenner Edward , Williams Marty 
Published: December 2007

Abstract
Recently new techniques have been developed for the purpose of solving a seismic image problem that is in part caused by fractures. Maps of velocity anisotropy can be used to predict the distribution of fracture intensity. Discrete Fracture Network (DFN) Models can be built on those maps of fracture intensity and then analyzed for engineering parameters. DFN model is constructed based on fracture intensities from a geologic analogue. Predictions based on only the fracture intensity, adding the geologic analogue, and adding an engineering analogue show that the interpretation of fracture intensity from seismic anisotropy will be improved by following geologic and engineering analogues.
Assessment of Mud-Filtrate Invasion Effects on Borehole Acoustic Logs and Radial Profiling of Formation Elastic Parameters
Authors: Chi Shihong , Torres-Verdin Carlos , Wu Jianghui , Alpak Faruk O. 
Published: December 2007

Abstract
Despite continued improvements in acoustic logging technology, logs processed with industry standard methods often remain influenced by formation damage and mud-filtrate invasion. Proper quantitative understanding of the process of mud-filtrate invasion is necessary to identify and assess biases in the standard estimates of in-situ compressional- and shear-wave velocities. We describe a systematic approach to quantify the effects of mud-filtrate invasion on borehole acoustic logs and introduce a novel algorithm to estimate radial distributions of elastic parameters away from the borehole wall. Radial saturation distributions of mud filtrate and connate formation fluids are obtained by simulating the process of mud-filtrate invasion. Subsequently, radial profiles of the elastic properties are calculated using the Biot-Gassmann fluid substitution model. Array waveforms are simulated using the calculated radial profiles of formation elastic parameters as input. Estimated compressional- and shear-wave velocities for homogeneous, stepwise, and multilayered formation model are compared to quantify mud-filtrate invasion.
A nonlinear Gauss-Newton inversion algorithm is used to estimate radial profiles of format1on elastic parameters in the presence of invaded zones using normalized spectral ratios of array waveform data. Inversion examples using synthetic and field data indicate that physically consistent profiles of formation elastic parameters can be reconstructed from array waveform data. In turn, radial profiles of formation elastic parameters can be used to construct more realistic near-wellbore petrophysical models for applications in reservoir simulation and production.
Optimum FractureTreatment Design Minimizes the Impact of Non-Darcy Flow Effects
Authors: Lopez-Hernandez Henry D. , Valko Peter P. , Pham Tai T. 
Published: December 2007

AbstractHydraulic fracturing is today the completion of choice in most of tight gas producing fields all over the world. Ultimate performance of fractured wells is severely diminished by the effects of non-Darcy flow inside the fracture. A design methodology based on the effective Proppant Number is presented in this paper.Non-Darcy flow is described by the β factor method. Evaluation and selection of appropriate β factor correlation is a key step in this approach. Effective fracture permeability and corresponding optimum geometry is calculated through an iterative process.The proposed methodology was implemented in the design of 11 fractures treatments of 3 tight gas wells in South Texas. Results show that optimal fracture design might increase expected production by 9.64 MMscf/day with respect to design that assumes Darcy flow through the propped pack. The basic finding is that for a given amount of proppant shorter and wider fractures compensate for a significant part of the non-Darcy effect. Optimum fracture geometry varies with the applied pressure drawdown (in contrast to the Darcy flow case, where it does not.)Optimum fracture design is sensitive to the particular β factor correlation selected. It is recommended to use the equation developed specifically for the given type of proppant and mesh size, if available. Otherwise, the Pursell et al. or the Martins et al. equations are recommended as across the board reliable correlations for predicting non-Darcy flow effects in the propped pack.
Dynamic Interfacial Tension Phenomenon and Wettability Alteration of Crude Oil-Rock-Alkaline-Surfactant Solution Systems
Authors: Li Jingquan , Wang Wei , Gu Yongan 
Published: December 2007

Abstract
It has long been recognized that an alkaline-surfactant (AS) flood is an effective enhanced oil recovery (EOR) process. When an AS solution is injected into an acidic oil reservoir, it causes the interfacial tension (IFT) reduction and wettability alteration, which subsequently affect the flood performance to a large extent. Quantitative descriptions of this dynamic IFT phenomenon and wettability alteration are of great interest to the petroleum industry. In this paper, the axisymmetric drop shape analysis (ADSA) technique for the sessile drop case is employed to measure the dynamic IFT and the contact angle of a crude oil drop on a reservoir rock in several aqueous solutions. Based on the modern digital image acquisition, analysis and processing techniques, the ADSA technique obtains the accurate digital image of the sessile oil drop and accomplishes the relevant measurements. The aqueous solutions include alkaline solutions and AS solutions at different alkali, cationic and anionic surfactant concentrations. It has been found that the measured IFT varies with time. This dynamic IFT phenomenon is then interpreted in terms of the surfactant generation and adsorption at the interface and its subsequent dissolution into the adjacent bulk phases as well. Meanwhile, it has also been observed that the measured contact angle changes with time in a peculiar manner. When the crude oil is made in contact with an alkaline solution, a water-wet reservoir rock quickly becomes more water-wet to different degrees at different alkali concentrations. At the beginning, the contact angle increases but eventually decreases close to its initial value. This wettability alteration corresponds well to the measured dynamic IFTs. In addition, the synergistic effects of AS solutions on wettability alteration are studied. It has been found that the wettability alteration in a cationic surfactant-alkaline solution has a rather different trend from that in an anionic surfactant-alkaline solution. More specifically, a cationic surfactant can make a water-wet reservoir rock become oil-wet, whereas an anionic surfactant can only cause minor change of its wettability. It is speculated that adsorption of the cationic surfactant onto the rock surface is strong and stable so that the wettability alteration is irreversible. This laboratory study not only provides an improved understanding of the interfacial interactions in the crude oil-reservoir rock-AS solution systems but also helps to fully develop the oil recovery potential of AS flood processes in field applications.
Mechanistic Prediction of Capillary Imbibition Curves
Authors: Gladkikh Mikhail , Bryant Steven 
Published: December 2007

Abstract
The importance of capillarity–controlled processes in porous media, such as drainage or imbibition, is hard to overestimate. In this work a new way of modeling imbibition is presented, which is based upon a physically consistent dynamic criterion for the imbibition of a pore originally proposed by Melrose.
The approach is applied in a dense random packing of equal spheres, which serves as a simple but physically representative model of a well–sorted, unconsolidated sediment. The results of the geological process of cementation (e.g. quartz overgrowth) are simulated in the sphere pack. The pore space geometry of the resulting model sedimentary rock is completely defined, which makes possible a priori predictions of pore level processes.
Imbibition is simulated in a network that naturally corresponds to the pore-space of the model rock. This allows quantifying the influence of different parameters, such as wettability (specified by the value of contact angle of fluid-fluid-solid interface), initial conditions (different drainage endpoints) and sample geology (amount of cement). It also provides a basis for a mechanistic understanding of phenomena such as "snap-off" of nonwetting phase in the pore throats.
The simulations show that the imbibition capillary pressure curve is very sensitive to the value of contact angle and degree of cementation. Predicted capillary pressure curves compare favorably with experimental data presented in the literature. In contrast, simulations with alternative criteria for pore-level events do not explain the data. We conclude that the dynamic criterion captures the relevant pore-scale physics for two–phase displacements. This provides a new foundation for understanding behavior of multiple fluid phases in porous media.
Pore Scale Characterisation of Carbonates using X-ray microtomography
Authors: Arns C. H. , Bauget F. , Limaye A. , Sakellariou A. , Senden T. J. , Sheppard A. P. , Sok R. M. , Pinczewski W. V. , Bakke S. , Berge L. I. , Øren P.-E. , Knackstedt M. A. 
Published: December 2007

Abstract
A reservoir carbonate core plug has been imaged in 3D across a range of length scales using high resolution X-ray microtomography (µ-CT). Data from the original 40 mm diameter plug was obtained at the vug scale (42 µm resolution) and allows the size, shape and spatial distribution of the disconnected vuggy porosity, φvug = 3.5% to be measured. Within the imaged volume over 32000 separate vugs are identified and a broad vug size distribution is measured. Higher resolution images, down to 1.1 µm resolution, on subsets of the plug exhibit interconnected porosity and allow one to measure characteristic, intergranular pore size. Pore scale structure and petrophysical properties (permeability, drainage capillary pressure, formation factor and NMR response) are derived directly on the highest resolution tomographic dataset. We show that data over a range of porosity can be computed from a single plug fragment. Data for the carbonate core is compared to results derived from 3D images of clastic cores and strong differences noted. Computations of permeability are compared to conventional laboratory measurements on the same core material with good agreement. This demonstrates the feasibility of combining digitized images with numerical calculations to predict properties and derive cross-correlations for carbonate lithologies.
Utilizing the Value of Continuously Measured Data
Authors: Holland Jeff , Oberwinkler Christian , Huber Michael , Zangl Georg 
Published: December 2007

Abstract
Smart Fields and Intelligent Wells are the new buzz words currently dominating in the petroleum industry. Many papers have been published so far on the implementation of intelligent wells but less has been seen on the actual application of the continuously measured data.
There are many different problems the engineer is facing during his attempt to use the real time data for real time optimization. Just to mention a few of them: Data qualityMoving huge amounts of dataMany engineering software packages are not able to handle high frequency data
Basically, the question is, how can the real time data stream be used for continuous asset optimization and is there any economic value to it?
The first part of the SPE paper will deal with a general introduction into current problems and how they can be solved.
The second part will give an actual example of the implementation of an Automated Reservoir Surveillance System1 in the Medusa field, Gulf of Mexico (GOM). Different levels of implementation have been identified: Data management and integrationAutomationReal time rate allocationDetection
The first three points have been successfully implemented. The remaining point is currently in progess. A detailed view will be given on the goals which should be achieved in the end - in particular how to actually use real time data for continuous monitoring and optimization.
The uniqueness of this approach lies in the continuous and automatic comparison of real values to estimated values based on computational models. If the two values deviate from each other, the engineer is notified by an alarm system. This is a powerful and new approach and can be seen as the first step towards a Smart Field implementation.
Multiphase Non-Darcy Pressure Drop in Hydraulic Fracturing
Authors: Olson Karen E. , Haidar Sami , Milton-Tayler David , Olsen Eivind 
Published: December 2007

Abstract
Valhall, an offshore field in Norway, is a black oil reservoir producing mainly through multi-fractured (with proppant) horizontal wells.1 The bottom hole flowing pressure is well below the bubble point and hence the fracture conductivity is significantly constrained by multiphase non-Darcy pressure drop losses.
Geertsma in 1974 was the first to propose a multiphase Beta (non-Darcy constant) correlation as a function of permeability, porosity (size) and saturation. Recent testing to measure the non-Darcy pressure drop for multiphase flow in proppant packs was successful in verifying a strong relationship to saturation.
Three different types of 16/20 proppants with three different resins and one of 12/18 and 20/40 were tested (total of eleven samples) in a conductivity cell under field conditions (temperature of 195 deg F and 1,500-6,500 psi confining stress), for a proppant loading of 4 Lb/ft2 The proppant was placed in the cell using a 30 lb crosslink borate X-link fluid with 4 ppt (lbs/1000 gal gel) of encapsulated breaker for 24 hours to allow fluid break prior to conducting the flow tests.
The Geertsma type equation was used to match the laboratory data. The equation constants (for permeability, porosity and saturation) for each proppant/resin type were derived. The non-Darcy correlations for each proppant were used in a numerical simulator to determine the pressure drop in the fracture and to quantify the effects on production rates.
The paper highlights the importance of proppant size for optimizing fracture design for wells producing under multiphase flow.