bluuebunny/crossref_metadata_2025_split huggingface dataset:
Tip Screenout Fracturing of Gas Wells
Authors: Fan Yong , Llave F. M. 
Published: December 2007

Abstract
Tip screenout fracturing, also known as frac&pack, has gained increasing prominence for well completion of unconsolidated and medium-high permeability formations. Oil wells with permeabilities up to 1,000 md have been treated using this technology. It is easy to postulate that gas wells with permeabilities of 50 md or higher can also be effectively frac&packed. This paper presents a model that describes the transient flow of polymer solution through a filter cake and the reservoir as a means to account for leakoff behavior during tip screenout fracturing of gas wells. The leakoff rate into the formation is determined by the pressure profile established during the treatment as a function of the properties of the fracturing fluid and the reservoir formation. Consequently, no constant bulk property (such as the leakoff coefficient) is used in the fracturing model. This paper shows how to terminate the fracture growth at the appropriate time, and how to design frac&pack treatments resulting in fracture widths several times larger than those from traditional fracturing.
The Impact of Integrating Static and Dynamic Data in Quantifying Uncertainties in the Future Prediction of Multiphase Systems
Authors: Huang Xuri , Gajraj Allyson , Kelkar Mohan 
Published: December 2007

Summary
This work presents a qualitative analysis of the uncertainties in performance prediction for a reservoir characterization process in which static and dynamic data are combined. Using primary, single-phase production data as the dynamic constraint in the inversion, we evaluate the quality of the models when they are used in alternative or subsequent production scenarios. We conclude that, provided the well configuration remains the same as that used for the dynamic constraint in the inversion, the models perform well when the production stage remains single-phase, primary depletion, even at the individual well level and for future prediction. For multiphase primary production, there is also a reasonable match in performance, although not as good as for a single-phase case. This is because such depletion processes are controlled by the permeability in the near-wellbore region, which is adequately reconstituted by the characterization process used; we observed, however, that the multiphase density variations with time had little impact. However, the fine scale, inter-well permeability patterns of the different realizations obtained by the integration of the dynamic and static data are not sufficiently resolved and so are unable to capture adequately the inter-well permeability heterogeneity patterns that are necessary for accurate waterflood performance matching. Thus, the models produced by inversion in which primary recovery data are used as a constraint are inadequate in predicting the performance of processes involving injection.
An Expandable-Slotted-Tubing, Fiber-Cement Wellbore-Lining System
Authors: Stewart R. B. , Gill D. S. , Lohbeck W. C. M. , Baaijens M. N. 
Published: December 2007

Summary
An expandable-slotted-tubing, fiber-cement wellbore-lining system has been developed. Its purpose is to temporarily secure the integrity of a wellbore section to allow drilling operations to continue through deeper overpressured or depleted zones. The lining is installed below the previous casing with no or minimal reduction in hole diameter.
The technology makes it possible to realize major reductions in well costs by avoiding the use of certain intermediate and contingency casing strings. It also helps in high-pressure/high-temperature (HPHT) well designs where the requirement for additional casing strings may become excessive.
The paper outlines the technologies involved and installation/ evaluation procedures. Details are given of onshore and offshore field trials in Europe and the U.S.
A Study of Oil/Water Flow Patterns in Horizontal Pipes
Authors: Trallero J. L. , Sarica Cem , Brill J. P. 
Published: December 2007

Summary
Oil/water flow-pattern transitions in horizontal pipes have been studied botd experimentally and tdeoretically. A new state-of-tde-art oil/water test facility was designed, constructed, and operated. A transparent test section (5.013-cm inside diameter × 15.54 m long) can be inclined at any angle, to study botd upward and downward flow simultaneously. Mineral oil and water were tde working fluids (µo/µw= 29.6, ρolρw= 0.85, and σ = 36 dynes/cm at 25.6°C).
A new classification for oil/water flow patterns based on published and acquired data is proposed. Six flow patterns were identified and classified into two categories: segregated flow and dispersed flow. Stratified flow and stratified flow witd some mixing at tde interface (ST&MI) are segregated flow patterns. tde dispersed flow can be eitder water dominated or oil dominated. A dispersion of oil in water over a water layer and an emulsion of oil in water are water-dominated flow patterns. An emulsion of water in oil and a dual dispersion are oil-dominant flow patterns.
The oil/water flow-pattern transitions for light oils are predicted using tde two-fluid model and a balance between gravity and turbulent fluctuations normal to tde axial flow direction. Stability analyses reveal tdat tde stratified/nonstratified transition must be addressed witd tde complete two-fluid model. Stratified flow is predicted by tde viscous Kelvin-Helmholtz (KH) analysis while in-viscid KH tdeory predicted tde ST&MI flow pattern. For tde dispersed flow pattern, tde predicted drop sizes from tde Hinze and Levich models are modified to account for tde effect of tde dispersed phase concentration. tde controlling parameter for tde coalescence phenomena is tde water fraction. tde model performance is excellent and compares well witd published data.
Acoustic and Petrophysical Properties of Seafloor Bedrocks
Authors: Assefa Solomon , Sothcott Jeremy 
Published: December 2007

Summary
There are few published velocity and attenuation data for seafloor bedrocks at appropriate confining pressures (1 MPa to 10 MPa). Velocities and attenuations measured at low pressures are affected mainly by open microcracks. However, as the pressure is increased and the microcracks are closed, the effect of microcracks on the velocities and attenuations will be minimal. At elevated pressures, the velocities and attenuations in rocks depend primarily on the elastic moduli of the rock-forming minerals and porosity, which results from the degree of alteration and diagenetic processes that acted on the rocks. The aim of this paper is to investigate the effect of microcracks on the acoustic properties at low pressures (10 MPa effective pressure) and the relationship between the acoustic, petrophysical, and geological properties of seabed rocks at high pressure (40 MPa effective pressure), where the effect of microcracks is minimal. Laboratory measurements of acoustic velocity and attenuation of this kind give a better understanding of these properties at the appropriate pressure (depth) for rocks undergoing different geological (e.g., diagenesis) processes than those buried at greater depth.
We measured compressional- and shear-wave velocity and attenuation on a suite of seabed sedimentary and igneous rocks of the northern U.K. continental shelf at effective pressures (confining less pore-fluid pressure) ranging from 10 MPa to 40 MPa. The measurement frequencies range from 0.5 MHz to 1 MHz. We used Winkler and Plona's 1 pulse-echo method to measure velocity and attenuation (quality factor). The porosity and permeability of the rocks range from 0% to about 20% and 0 to about 5 md, respectively. X-ray diffraction (XRD) analysis, petrological studies of polished thin-sections, and scanning electron microscope (SEM) observations show that most of the sandstones have a significant clay content (e.g., kaolinite, illite, and chlorite) and fractures. Most of the igneous rocks are chloritized.
We show that the velocities and quality factors of the rocks studied are much lower than those of similar continental rocks. Microporosity formed by the alteration of feldspars, micas, and mafic minerals to clays (e.g., chloritization of pyroxenes) and the corresponding reduction of the elastic moduli are the major processes that result in low velocity and quality factors. Velocity and attenuation models of seabed rocks are critical for the interpretation of seismic data for rocks buried at greater depth. The results of this study suggest that values of velocities and quality factors used for modeling purposes should be lower than assumed normally.
Field Operational and Performance Issues of Polymeric Water-Control Agents
Authors: Lane R. H. 
Published: December 2007

Summary
This paper describes field experience with low- and high-molecular-weight partially hydrolyzed polyacrylamide (PHPA) polymers crosslinked with Cr(III) carboxylate species. On the basis of that experience, the paper addresses successes and limitations in terms of downhole temperature, precooling, chemical delay of crosslink time, length of time for treatment application, quality control of polymers from different sources/batches, equipment considerations, and premature-gelation issues. The paper also visits some general field considerations, including the importance of robustness of the chemistry employed.
Two-Phase Pressure-Drop Predictions Across Gravel Pack
Authors: Ates Harun , Kelkar Mohan 
Published: December 2007

Summary
In applying nodal analysis to optimize the performance of a single well, it is critical that we are able to estimate the pressure drop across each of the components of a complete well system, from the outer boundary of the reservoir to the sandface, from the tubing string to the separator including any restrictions, safety valves, and surface choke. Relationships for rate vs. pressure drop under single-and two-phase flow conditions are available for most of the components with the exception of perforations and gravel pack. This paper presents the procedure for calculating the pressure drop across perforations and gravel pack under two-phase flow conditions. Results are presented indicating the difference between single- and two-phase flow calculations. It is shown that if the two-phase flow is not properly accounted for, we can significantly underestimate the pressure drop across the gravel pack and perforations.
Productivity of Horizontal Sinks in the Presence of Distributed Fractures
Authors: Sato Kozo 
Published: December 2007

Summary
The steady-state productivity (Jh) of horizontal sinks (hydraulically fractured wells or horizontal wells) in the presence of regularly arranged and stochastically distributed fractures is studied. Numerical experiments are conducted in two dimensions to investigate several factors affecting Jh, which include the number of fractures, the mean of fracture lengths, fracture inclination, and horizontal-sink length and location.
For 500 simulation outcomes, parametric correlations between Jh and possible regressor variables are obtained. It was found that the overall-fracture parameters (the number of fractures and the mean of fracture lengths) alone could not yield good correlations. Including near-sink fracture configurations in a set of regressor variables improves the quality. With the developed correlations, individual contributions of the horizontal sink, near-sink fractures, and overall fractures to Jh are examined. The findings obtained in this study are of help when designing horizontal sinks to be completed in fractured reservoirs.
Transient Behavior of Finite Conductivity Horizontal Fractures
Authors: Valkó Peter , Economides Michael J. 
Published: December 2007

Summary
In this work a semi-analytical solution method is elaborated to obtain the transient behavior of a vertical well intersected by a finite conductivity horizontal ("pancake") fracture. Both the constant production rate and the constant drawdown cases are considered. Permeability anisotropy and non-homogeneous formation structure are incorporated into the model formulation. The results can be used to evaluate pressure transient testing and/or to forecast the production increase. Comparison with the uniform flux and infinite conductivity solutions brings light to the effects neglected in those approximations. Late time pseudoradial behavior is interpreted in terms of pseudo-skin factor and the issue of optimal fracture conductivity is addressed.
East Spar Development: NCC Buoy - The Vertical Submarine
Authors: Boyle E. C. 
Published: December 2007

Summary
The remote East Spar gas/condensate field has been developed using a subsea production system operated by an unmanned navigation, communication, and control (NCC) buoy. The use of this type of sys- tem allows control of the field from any convenient location, with the command-response time and the cost of the facility almost complete- ly independent of the distance to the shore or host facility. Successes during the project (such as using model tests to prove the concept and using a tension-leg mooring system to reduce the motion response of the buoy) are discussed and compared to failures, like the weight and size growth of the structure, caused as the design requirements were finalized and external factors changed. The operation and layout of this facility is summarized, showing why it was described as a vertical submarine. Conclusions are drawn about the use of an NCC buoy to develop this field, showing that the main objectives have been achieved. The limited operating experience to date is also considered in the review of the design objectives. The paper concludes with the possibilities for the future of this type of concept.
Network Modeling of Three-Phase Flow in Porous Media
Authors: Fenwick Darryl H. , Blunt Martin J. 
Published: December 2007

SummaryWe present a network model of three-phase flow in water-wet porous media. To explain the high oil recoveries in gas injection and gravity drainage experiments, we show that the mechanism for oil recovery is flow through connected oil layers in the pore space that are on the order of a micron thick. We then describe a simple model for the configuration of oil, water, and gas in a single pore and present an approximate expression for the conductance of oil layers. We use this expression to derive the oil relative permeability when flow is dominated by layer drainage. We show that for low oil and water saturations kro∼So2, consistent with the results of several experiments. To predict kro for the full range of oil saturation we use a capillary equilibrium-based network model that can simulate any sequence of oil, water, and gas injection. We introduce a self-consistency procedure to ensure that the correct sequence of saturation changes is used in the network model to compute relative permeability. We then present relative permeabilities and oil recoveries for gas injection into different initial oil saturations, and for waterflooding a reservoir containing gas and oil. We show that the relative permeabilities are strongly affected by the fluid properties and by the type of displacement process.
New Fluosilicic Acid System Removes Deep Clay Damage
Authors: da Motta Eduardo P. , dos Santos J. Altamiro C. M. 
Published: December 2007

Summary
Recent models for sandstone acidizing have shown that the secondary reaction of fluosilicic acid (H2SiF6) with clays plays a significant role in the removal of formation damage. The conventional wisdom is that possible precipitation during the secondary reactions can adversely affect treatment success. However, this paper presents laboratory experiments with Berea cores and two Brazilian sandstone cores, as well as with field tests, that show that fluosilicic acid can be injected, by itself, into a sandstone reservoir without causing any damage. In fact, mixtures of fluosilicic acid, with a proper amount of hydrochloric acid (HCl) or an organic acid such as acetic acid (HAc), have been able to improve the performance of two Brazilian water-injection wells by removing clay damage. These two wells, which were injecting 11 and 15 m3/d, respectively, are sustaining injection rates at or above the desired quota of 30 m3/d 5 months after the treatments. The treatments were monitored with a real-time monitoring program, which showed that the skin factor has dropped from about 30/40 to zero. Besides having a lower cost than conventional hydrofluoric acid (HF) mixtures, the main advantage of the new acid system is that it reacts mostly with clays and feldspars, but it almost does not react with quartz. Thus, it can dissolve damage without weakening the rock structure, which makes it suitable for deep damage removal. The low cost of H2SiF6, which is a byproduct of sodium fluoride manufacturing, also makes it a viable option for routine acidizing operations that normally would require the use of an HF acid system.
Probabilistic Reserves! Here at Last?
Authors: Capen E. C. 
Published: December 2007

Summary
Recently, SPE and the World Petroleum Congresses (WPC) modified earlier definitions of reserves for the industry. Through much lobbying about improving the definitions, the committees generally clung to the past.
In truth, reserves have always been about probability because there has always been uncertainty as to proved, probable, and possible reserves. This paper proposes to dust off some of the mystery about how to deal with reserves probabilistically and correct some common procedures that do not follow the laws of probability and thus produce the wrong answer. For example, despite the reasonableness of the rule, it is illegal to add proved reserves from wells to get proved field or reservoir reserves. Every engineer who uses that method shortchanges his client and misleads the investors.
Comparisons of Uncoupled and Various Coupling Techniques for Practical Field Examples
Authors: Samier P. , Onaisi A. , Fontaine G. 
Published: December 2007

SummaryGenerally, in classical reservoir studies, the geomechanical behavior of the porous medium is taken into account by the rock compressibility. Inside the reservoir simulator, the rock compressibility is assumed to be constant or to vary with the pressure of the oil phase. It induces some changes in the porosity field.During the depletion phase or the cold-water injection of high-pressure/high-temperature (HP/HT) reservoirs, the stress state in and around a reservoir can change dramatically. This process might result in rock movements such as compaction, induced fracturing, and enhancement of natural fractures and/or fault activation, which continuously modify the reservoir properties such as the permeabilities and the fault transmissibilities.Modifications of such parameters strongly affect the flow pattern in the reservoir and ultimately the recovery factor.To capture the link between flow and in-situ stresses, it becomes essential to conduct coupled reservoir-geomechanical simulations.This paper compares the use of five types of approach for the reservoir simulations:A classical approach with rock compressibility using only a reservoir simulator. A loose coupled approach between a reservoir simulator (finite volumes) and a geomechanical simulator (finite elements). At given user-defined steps, the hydrocarbon pressures calculated by the reservoir simulator are transmitted to the geomechanical tool, which computes the actual stresses and feeds back iteratively the modifications of the petrophysical properties (porosities and permeabilities) to the reservoir simulator. A one-way coupling: this approach is a simplification of the loose coupled approach in that the modifications are not fed back to the reservoir simulator. A simplified approach using permeability and porosity multipliers inside a reservoir simulator. These multipliers are user-defined curves and vary with the pressure of the oil phase. This approach uses only a reservoir simulator. A coupled approach in which the structural and the flow unknowns (displacement, pressure, and saturations) are solved simultaneously.These approaches are compared for two validation cases and two field cases described in the following.
On Reservoir Fluid-Flow Control with Smart Completions
Authors: Ramakrishnan T. S. 
Published: December 2007

SummaryPoor displacement efficiency in hydrocarbon formations is often caused by the natural variation in the mobility of fluids across the reservoir strata. Historically, completions with cemented casing, packers, conformance controlling fluids/gels, and selective perforations have been used to mitigate the disparities in water encroachment over the reservoir interval. Recently, completion technologies using downhole valves, which allow production and injection control over multiple zones, have become available. The central idea is that downhole control may be used to adjust flow distributions along the wellbore to correct undesired fluid-front movement.In this paper, we address several technical issues related to downhole controls. We consider a single system comprising the reservoir, the completion, the measurement, and the feedback algorithm that adjusts flow-control devices, with quantitative models for each of the components. Both pressure and flow-rate control systems are discussed. Downhole control is modeled for electrical, reversible hydraulic, and unidirectional hydraulic valves. The design methodology for different valve systems is described and the disadvantages of hydraulic systems are discussed. In particular, it is shown that in conjunction with an automated feedback control, hydraulic valves will oscillate. Computations also show that all other factors remaining equal, these oscillations occur most easily in low-permeability zones. For unidirectional hydraulic valves, we also illustrate novel anticipatory control algorithms that prevent overshooting.For communicating layered systems, a front movement equation is derived using perturbation techniques. This technique provides the zone of influence of wellbore flow-control devices, and illustrates the maximal benefit that may be obtained through down-hole control, thus providing a ready comparison with the cost of completion.