bluuebunny/crossref_metadata_2025_split huggingface dataset:
Research and Application of Recirculating Foam Drilling and Completion Fluid
Authors: Sui Yuehua , Cheng Xiaohua , Sun Qiang , Ji Hongtao , Gao Jianli , Gao Qinghua , Zhuang Zhiwei , Qing Jishun , Zhou Aizhao 
Published: December 2007

Abstract
The re-circulating foam drilling and completion fluids (RFDCF) is a low density system developed by Shengli Drilling Mud Company of China. Its outstanding advantages are that no special equipment needed in field operation, the density can be adjusted between 0.60-0.99g/cm3 and can be re-circulated. The laboratory evaluation proves that the density of RFDCF decrease with the increase of temperature and is always lower than 1.00g/cm3 even in the pressure of 40Mpa. The on-site application in 48 wells proves that it can be used in high-angle well, horizontal well and under-balance drilling operation. It successfully solves the serious loss in buried hill formation of Shengli Oil Field and make important break through in oil production from igneous rock formation. The use of RFDCF greatly cut down the drilling expense and makes significant economical and social benefit.
Details of In Situ Foam Propagation Exposed with Magnetic Resonance Imaging
Authors: Wassmuth F. R. , Green K. , Randall L. 
Published: December 2007

Abstract
Transient and steady state foam propagation experiments in carbonate packs were imaged with a Magnetic Resonance Imaging (MRI) instrument. In situ saturation profiles can be resolved with MRI to a greater degree than previously tried methods.
Transient foam propagation experiments were carried out by co-injecting surfactant solution and gas into water saturated, carbonate packed, cores. In the case where surfactant adsorption was not initially satisfied, a unique water saturation wave developed between the advancing gas front and the lagging foam (lagging due to surfactant adsorption). In the experiment where surfactant adsorption was satisfied before injecting the foam, a stable foam front propagated at a rate close to the combined gas and liquid injection rate.
Steady state foam experiments were carried out at a variety of foam qualities. The saturation profiles along the length of the carbonate pack demonstrated two distinct regions, the foam generation region in the first 3 cm of the core and the foam propagation region in the remaining part of the core. With the enhanced resolution of MRI, small saturation changes with change in foam quality were evident in the foam propagation region. Previously, such small changes in liquid saturations during foam experiments were ignored and lumped together into the critical water saturation required for foam propagation.
Asphaltene Precipitation and Alteration of Wetting: Can Wettability Change during Oil Production?
Authors: Al-Maamari Rashid S. H. , Buckley Jill S. 
Published: December 2007

Abstract
Wettability controls the distribution and flow of immiscible fluids in an oil reservoir and thus plays a key role in any oil recovery process. Once thought to be a fixed property of each individual reservoir, it is now recognized that wettability can vary on both microscopic and macroscopic scales. Polar oil components can adsorb onto the pore-bounding mineral surfaces by several different mechanisms. In this study, we explore a transition in the mechanism of wettability alteration that relates to the asphaltene fraction and its stability in the oil phase.
Asphaltene stability was varied by addition of n-heptane to samples of five crude oils. Conditions ranged from asphaltene stability to mixtures in which aggregates formed and separated from the oil. The onset condition—where the first asphaltene particles become visible—was used as a reference point with respect to asphaltene stability in each crude oil sample.
Muscovite mica sheets, treated with brine and with the crude oil-heptane mixtures, were examined using contact angles between decane and water as a measure of altered wettability on the oil-treated surfaces. A significant increase in oil-wet conditions very near the onset of asphaltene precipitation was observed with four of the five oils, indicating the potential for wetting changes during the course of oil production if conditions of asphaltene instability are approached. Implications of changes in the mechanism of wetting alteration during the course of production from an oil reservoir are considered.
A Process-Based Approach for Three-Phase Capillary Pressure and Relative Permeability Relationships in Mixed-Wet Systems
Authors: van Dijke M. I. J. , Sorbie K. S. , McDougall S. R. 
Published: December 2007

Abstract
In the reservoir simulation of three-phase displacement processes, the saturation dependency of three-phase relative permeabilities is of central importance. However, little is known a priori about these saturation dependencies in nonstrongly water-wet systems. This behavior is intimately connected with the pore-scale physics of these displacements for the specific wettability state of the system. We refer to a model, which connects the macroscopic properties with the underlying pore-scale physics as a process-based model. In this paper, and in related work, such a model has been developed to determine the saturation-dependency regions of three-phase relative permeabilities. This processes-based model applies to both non-spreading and spreading oils for all types of mixed-wet and fractionally-wet porous systems that contain clusters of oil-wet and water-wet pores. Based on a classification of all allowed pore occupancies in a completely accessible porous medium, saturation-dependencies of the corresponding relative permeabilities are derived. The variation of regions in saturation space where the three-phase relations depend on either one or two phase saturations is determined and analysed in terms of the basic parameters of the model, i.e. range of pore size distribution, fraction of water-wet pores and the interfacial tensions (σgw, σgo, σow ).Furthermore, three-phase relative permeabilities that appear to depend only on their own saturations are either linked to the corresponding two-phase relative permeabilities or it is shown that such a link cannot be established. A comparison has been made with existing relative permeability models with respect to their saturation-dependencies.
CO2 Injection in the Weyburn Field of Canada: Optimization of Enhanced Oil Recovery and Greenhouse Gas Storage With Horizontal Wells
Authors: Malik Qamar M. , Islam M. R. 
Published: December 2007

Abstract
Recently, a billion-dollar CO2 injection project has been launched to increase oil recovery in the Weyburn field of Canada. Initially, the project will use 5000 tonnes of CO2 daily in 19 patterns. The background economic calculations use the assumption that miscibility will be achieved and a steady supply of CO2 at a cost of $35/tonne will be available. This paper provides detailed results of a comprehensive reservoir simulation study using a fully compositional model, in order to optimise the pattern and injection/production strategies.
The prototype reservoir models developed are by integrating geologic and petrophysical data available in the literature (1960-1998) for the Weyburn unit, in the southeastern part of Saskatchewan, Canada. The models provide successful history matching, optimise secondary and tertiary recovery schemes, predict an incremental oil recovery through improved oil recovery, and give an estimate of the subsurface storage capacity of greenhouse gases (GHG). The validity of the models developed is evident from the agreement obtained and the conclusions drawn from these diverse data sources that enabled a successful history match of the fluid movement in the reservoir. The models developed are robust in nature and helped determine key parameters controlling miscible CO2 flood. The effects observed due to the contaminated gas stream highlight several of the significant unexplained phenomena, faced by the industry. They are: role of impurities in controlling mobility of the injected gas, effect of impurities in the GHG stream, effect of the loss of miscibility, effect of gas injection directly into the bottomwater zone and the effect of bottomwaters transmissivity on oil recovery.
A technical conflict is encountered towards the optimal operating conditions for simultaneous objectives of higher recovery and higher CO2 storage. In this study, horizontal injection wells have proved to be efficient for CO2 flooding process to improve recovery while increasing the storage of anthropogenic CO2. Twenty-one different scenarios for two different schemes have been simulated and investigated simultaneously for storage and recovery. The incremental recovery is related to the flood injection operating strategies employed, introducing back pressure on the reservoir through injectors and producers. The CO2 flood front is controlled through horizontal well adjusting pressure, simultaneously adjusting water injection in the offsetting vertical injection wells and holding back pressure on the associated production wells. Efficient back pressure, achieved is by limiting high operating bottom hole pressure of the producers corresponding to those of injectors that helped maximise the vertical sweep. In addition, opting GOR strategy, location of the horizontal well, optimal injection rates helped to achieve conformance within the reservoir that enabled one to overcome the conflict of achieving the simultaneous objectives.
Influence of Geological Features on Well Test Behavior
Authors: Zambrano Judith , Zimmerman R. W. , Gringarten A. C. 
Published: December 2007

Abstract
Early recognition of porosity and permeability contrasts in a reservoir has economic implications in reservoir management. Reservoir characterization aims at developing a detailed knowledge of the geological heterogeneities that may affect production rates and recovery factors. In the area of reservoir characterization, geological and engineering data have been traditionally inverted separately: a 3-D static reservoir model is established from static data (geology, geophysics and petrophysics) and the parameter distributions in that model are adjusted by history matching with production and other dynamic data. The underlying assumption in this process is that production data correspond to the same model as static data (Floris et al.1; Landa et al.2). This may or may not be the case. Hence, the requirement to first identify separately a model for each type of measurement and to verify that each model is consistent with all the others. Because identification is an inverse problem, with a non-unique solution, it is also desirable to confirm each feature of the reservoir model with different types of measurements3. For some features this is possible with today's technology. For instance, well test analysis can confirm the location of a fault identified from geophysical measurements and vice-versa. Other features, on the other hand, require additional development.
The present work looks at the medium-scale architectural elements that have been formed in different depositional environments,, with the objective of reconciling geological and well testing modeling in order to increase the confidence in the evaluation of fault sealing, sandstone bodies geometry and lithofacies distribution. In this approach, the heterogeneities are regarded as geological objects characterized by geometrical parameters as well as by petrophysical properties. Synthetic genetic-type objects are generated by stochastically modeling their external geometries and internal rock-property distribution and their response in a well test is evaluated with the help of a numerical well test simulator. The systematic evaluation of the well testing responses of various geological objects yields a new source of reliable information for reservoir characterization.
Estimating Oil Reserves in Oil-Water Transition Zones
Authors: Christiansen R. L. , Heymans M. J. , Fanchi J. R. 
Published: December 2007

Abstract
The amount of recoverable oil in an oil-water transition zone depends on the distribution of oil saturation as a function of depth, and the relationship between initial oil saturation in the transition zone (Soitz) and residual oil saturation in the transition zone (Sortz). Traditionally, it is assumed that Sortz is the same as the residual oil saturation in the oil column (Sor) above the transition zone. However, data in the literature show that residual oil saturation depends on initial oil saturation. So, residual oil saturation in the transition zone (Sortz) should be a function of initial oil saturation in the transition zone (Soitz). The relationship between Sortz and Soitz is referred to as a trapped oil relationship.
The purpose of this paper is to show recent experimental corroboration of the trapped oil relationship and to demonstrate the impact of the trapped oil relationship on reserves determination in oil-water transition zones.
First, fundamental issues for appropriate selection of rock-fluid properties for characterizing transition zones are addressed. Graphical illustrations are presented to compare and contrast conventional methods for characterizing transition zones with an improved characterization method that requires additional rock-fluid property measurements.
Then, results from laboratory studies of recovery from transition zones are used to demonstrate features of the improved characterization method. These results show that oil in the transition zone is much more mobile and recoverable than is assumed by the conventional approach.
For these laboratory studies, unconsolidated packs of sand, glass beads, and plastic beads were used. The media were varied to observe the effects of wettability and grain size on transition zone properties. It is believed that the variety of media qualitatively represent what would be observed for actual reservoir formations. Local saturations in the transition zones were correlated to gray level of video images of the surface of the packs. The laboratory methods for unconsolidated media could be extended in the future to reservoir rock (having much lower permeabilities) with centrifuge technology.
Finally, the effect of the trapped oil relationship on reserves determination is shown with an extended black oil simulation that incorporates the effects of relative permeabilities on reserves determination.
Gas Management in a Large, Complex, Miscibly Flooded Oil Field
Authors: Dunn M. D. , Lagerlef D. L. , Chamberlain J. A. 
Published: December 2007

Abstract
The Kuparuk River Field, on the North Slope of Alaska, is an extremely complex system when predicting and managing produced gas and artificial lift gas. Encompassing an area of almost 200 square miles, it is one of the largest full-field waterfloods in the world. On a daily volume basis, it is the second largest miscible gas flood in the world, second only to Prudhoe Bay. The field has approximately 400 gas-lifted wells and a dozen wells on ESPs. Currently, the field is characterized as "formation gas constrained" because wells over a formation GOR of ~6000 scf/bbl must be shut-in. Fluids are processed and gas is compressed at three different processing plants, with some processes being shared between plants, and other processes being independent. Combined with a reservoir that is composed of two distinctly different sands, makes reservoir management and particularly gas management, an extremely challenging task.
In late 1998 a multi-disciplinary team was assembled to develop a framework and implement tactics that would better optimize gas handling at Kuparuk. At the time, several nearby "satellite" fields had just come on-stream that further taxed the existing gas handling capacity and oil prices were such that expansion projects were unattractive. This Gas Management Team was charged with optimizing reservoir, gas lift, and equipment performance. This required developing a better understanding of the leveraging mechanisms and processes, and communicating a set of tactics that could be implemented by the Organization.
This paper discusses the work of the Kuparuk Gas Management Team, composed of EOR, reservoir, optimization, and process engineers. This team studied the various facets of gas injection, gas production, gas storage, and gas lift to establish a plan to optimize this system. Efforts and topics that will be discussed are as follows:
More consistent measures of gas handling capacities Methods to improve forecasts of gas production Identification of the reservoir management "levers" that effect gas production Definition of the value of gas lift and the importance of quality data
Results to date show the optimization target was significant, and that much of it was achieved by applying the recommended tactics. This paper should benefit anyone who is working large fields where gas is re-injected for disposal or EOR purposes. It should also benefit those working gas-lifted fields where the value of gas lift must be understood in order to optimize the entire system.
Development and Field test of a Stabilizer with FGM Blades
Authors: Suehiro Y. , Ikegaya A. , Tsuda K. , Miyagawa T. 
Published: December 2007

Abstract
Functionally Graded Material (FGM) has the potential to endure in a deep well and sour environment. Japan National Oil Corporation (JNOC), Japan Research and Development Center for Metals (JRCM) and Sumitomo Electric Industries, Ltd. (SEI) applied FGM to a stabilizer blade and then developed a prototype stabilizer with it. This FGM is composed of Cobalt- composition graded cemented carbide layers and a steel substrate with lower Co composition in the surface. The graded cemented carbide powders stacked on steel were sinter-bonded by pulse-current resistance heating. We manufactured the desired structure and confirmed the stress relief, high bonding strength, and distribution of functionality of coated layers between the surface (with high wear resistance) and the inside (with high toughness). The new stabilizer, with FGM blades composed of WC-25%Co (thickness of the layer is 1.5mm) and WC-40%Co (thickness of layer is 1.5mm), was tested in the Kashiwazaki Test Field (KTF) well and in the Ministry of International Trade and Industry's (MITI) Sanriku-oki well in Japan. To compare a conventional type of stabilizer which has cemented carbide buttons with this new stabilizer, we drilled with both stabilizers for about 270m in the KTF well and for about 980m in the MITI well. The wear resistance of FGM blade was more than 2 times that of the conventional blade in the KTF well and more than 20 times higher in the MITI well. These results suggest that we might expect the new stabilizer to have high performance in deep wells and to achieve at least twice the tool life of conventional stabilizers while drilling.
Development of an Integrated Reservoir Model for a Naturally Fractured Volcanic Reservoir in China
Authors: Abbaszadeh Maghsood , Corbett Chip , Broetz Rolf , Wang James , Xue Fangjian , Nitka Tom , Zhang Yong , Liu Zhen Yu 
Published: December 2007

Abstract
This paper presents the development of an integrated, multi-discipline reservoir model for dynamic flow simulation and performance prediction of a geologically complex naturally fractured volcanic reservoir in the Shang 741 Block of the Shengli field in China. The reservoir contains a series of vertically separated fractured volcanic reservoirs with different size and fracture intensity. A static geological model of the reservoir is developed based on integration of principles of lithological depositional setting, petrophysics, fracture analysis and stochastic fracture network modeling using FormationMicroImager (FMI) log data, a 3D seismic survey and advanced seismic interpretations.
A simulation model for the reservoir is constructed in a step-wise fashion by properly combining multi-disciplinary data sources, anchored with sound principles of reservoir engineering and geoscience. Information from single well and interference pressure transient data as well as water cut information from wells help assign key dynamic controls on the reservoir. These include effective fracture permeability magnitude, quantification of fracture-matrix interaction, reservoir unit compartmentalization, and flow transmissibility characteristics of conductive faults. As a result of synergy and multiple iterations among various disciplines and utilization of integrated project teams, a reliable history matched dynamic reservoir model capable of future performance prediction for optimum asset management is constructed. Among many scenarios investigated, it is found that implementation of water injection schemes would provide optimum recovery mechanism for the Shang 741 Block field.
Portfolio Optimization using Efficient Frontier Theory
Authors: Merritt Don , Miguel Andre de San 
Published: December 2007

Abstract
In an oil and gas industry full of acquisitions, divestitures and mergers, it is now more important than ever for an oil and gas producer to carefully plan its portfolio of assets. Efficiency and profitability must be balanced against overall risk. This paper re-introduces portfolio optimization via the efficient frontier theory and also investigates a worked example of portfolio optimization.
Petroleum companies are constantly faced with difficult investment decisions. Made in isolation, these investments will only maximize the value of the individual asset. In order to balance the risk and exploit project synergies, investment decisions should be made collectively. Portfolio optimization using the efficient frontier analysis is an investment decision making technique that quantifies the selection of multiple investment opportunities such that risk is minimized, and value is maximized – over a complete portfolio.
Modern portfolio theory is regarded as among 20th-century finance's most important analytical tools. Portfolio optimization was originally created as a securities investment optimization tool. This is based on the theory that given the expected return and risk of a security, along with its correlation with other securities in a portfolio, a selection of stocks can be chosen that maximizes the return for any level of risk.
Harry M. Markowitz, an economist at the University of Chicago, and William F. Sharpe at Stanford University, were awarded the Nobel Prize in 1990 for over twenty years work with modern portfolio theory. Markowitz’ original 1952 paper1 suggested that each portfolio of assets would have a given level of risk and reward, but that for any level of risk, there was only one portfolio that would return an optimum reward. Conversely, for any level of reward, there would be only one portfolio that would minimize the risk.
The discussion that follows presents the portfolio optimization theory as applied to an oil and gas portfolio of investments.
The worked example will look at a small collection of assets ranging from existing production to wildcat exploration opportunities. In the context of this example, the paper will explore the questions of:
➢ What is the best mix of exploration opportunities vs. development opportunities? ➢ What is the spectrum of possible outcomes of the portfolio? ➢ What is the mixture of return/reward for the different portfolios?
The paper will also present a technique for the empirical generation of the efficient frontier via Monte Carlo simulation.