bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Analysis of Advection-Dispersion Ratio to Incorporate Dispersive Transport into Streamline Simulation
Authors: Jang Minchul , Lee Jaehyoung , Choe Jonggeun , Kang Joe M. 
Published: December 2007

Abstract
Streamline simulations have been extensively used due to its computational speed and freedom from numerical dispersion. However, many works have been applied to transport modeling without considering dispersive transport. A new term, an advection-dispersion ratio is introduced, which is defined as a relative extent of advection to dispersion along a streamline. Using the advection-dispersion ratio, analytical solution to the advection-dispersion equation is mapped onto streamlines so that dispersive transport can be effectively modeled by streamline simulation. With the advection-dispersion ratio incorporated, streamline simulation was applied to transport in an artificially fractured sample, and the simulation result was compared to experimental result. It is observed that the tracer breakthrough curve from the simulation matches well with that from the experiment. In addition, the tracer displacement profile matched that of experiment well.
By allocating various advection-dispersion ratios to streamlines, streamline simulations were performed on various fields generated by sequential Gaussian simulation to analyze the effect of the advection-dispersion ratio on transport modeling. Then, the results were compared with simulation result using a single representative advection-dispersion ratio over the flow domain. The simulation results indicate that a representative advection-dispersion ratio is applicable when the advection-dispersion ratio is large. On the other hand, advection-dispersion ratio should be allocated differently to each streamline with respect to the characteristics of the streamline, when the representative advection-dispersion ratio is small. Moreover, similar permeability is apt to be clustered spatially in a field of high correlation length, which yields diverse and contrastable streamline characteristics in the standpoint of advection-dispersion ratio. Therefore, the results using the single representative advection-dispersion ratio differ from those using various advection-dispersion ratios along individual streamlines.
The New Gulf of Mexico National Pollution Discharge Elimination System Permit: How does it Shape up?
Authors: Hall John 
Published: December 2007

Abstract
December 2001 marked the introduction of a new modification to the EPA National Pollution Discharge Elimination System (NPDES) Permit for Region 6 (Gulf of Mexico.) The changes related to the permit's coverage of the discharge of synthetic based fluids on cuttings. Regulators in other areas of the world, for example North Sea and Nigeria, have also permitted discharge of synthetic based fluids on cuttings. However, time has seen increasing restriction of discharge rules and has also seen operators forced to go to zero discharge of synthetics base fluids. The permitting of discharge, followed by tightening of regulations, and, sometimes, ultimate moves towards zero discharge by regulators has had a profound impact on usage, development, and availability of synthetic based drilling fluids.
This paper lists key events regarding environmental regulations and follows the developments following the introduction of the new NPDES Permit for the Gulf of Mexico from the perspective of a drilling fluid supplier and examines industry reactions to the implementation of the permit. It also seeks to answer two key questions from the supplier's perspective-"How is this rulemaking different from that seen in other areas in the world?" and "Is the next regulatory step for the Gulf of Mexico zero discharge"?
Low Field NMR Water Cut Metering
Authors: Wright Ian W. , Lastockin David , Allsopp Kevin , Evers-Dakers Maureen , Kantzas Apostolos 
Published: December 2007

Abstract
We have developed a new on line water cut meter using low field Nuclear Magnetic Resonance (NMR) technology. This instrument is designed for use on heavy oil systems where conventional instruments experience difficulties.
We present laboratory and field data for application of low field NMR to water cut measurements of bitumen/water mixtures. Data from successful field tests near Cold Lake, Alberta, Canada, shows that the instrument is capable of making water cut measurements over a wide range of fluid types and temperatures. We have successfully measured fluid streams with temperatures ranging from 60 to 150 degrees Centigrade and with water cut ranging from 40 to 95 percent. The instrument is capable of functioning accurately over a wide range of emulsions and/or foams and through significant variations of water salinity.
The current application is for water cut measurements on a well site. However, the instrument can be applied in any system where heavy oil, bitumen, water, gas and solid systems may be encountered. It can be used for water cut and/or for three phase (oil/water/gas) volume fraction measurements. The instrument is equally capable of performing well site monitoring for regulatory/reconciliation purposes, for characterizing produced fluids, in separation, pipelining and upgrading processes for process control and for quality testing.
New Concepts of Dual-Completion for Water Cresting Control and Improved Oil Recovery in Horizontal Wells
Authors: Inikori Solomon O. , Wojtanowicz Andrew K. 
Published: December 2007

Abstract
The primary advantage of horizontal wells is the long penetration and small pressure drawdown. Thus, horizontal wells have been used for developing reservoirs experiencing severe water coning problems.
However, several field experiences indicate that horizontal wells are also not free from the problem of water coning (otherwise known as water cresting). In some field reports, water breakthrough into horizontal wells could be quite dramatic and tend to erode the merit of high deliverability. Field experiences also indicate that the horizontal well fluid inflow profile is not uniform along the well but rather asymmetrically skewed toward the heel of the well. Thus water tends to breakthrough first at the heel (downstream end) and spread toward the toe-end (upstream end) of the well.
In this paper, the authors present the result of a tool developed to effectively evaluate the problem of pressure loss in the wellbore and its effect on water cresting in horizontal wells. The tool incorporates the effects of several factors such as in-situ pipe roughness, perforation size and perforation density, axial fluid influx and two-phase oil-water flow. The results could be extended to three-phase flow by adequate gas-liquid correlations.
The paper also presents a study of two innovative concepts of "smart" completions for controlling water cresting in horizontal wells: "tail pipe water sink" and "bi-lateral water sink". The technologies involve the segregated production of oil and water in a dual completion with zonal isolation. The results of this research using commercial numerical reservoir simulators indicate that dual completions are capable of reducing the incidence of by-passed oil at the toe of horizontal wells and improve oil recovery by over 7 percent.
Exploration Economics of Multizone Prospects: A Comparison With Single Zone Approximations
Authors: Mudford B. 
Published: December 2007

Abstract
Many deepwater exploration prospects are composed of multiple stacked zones of pay. In general, each zone has a geologic probability of success, a probability of oil, and a distribution of technically recoverable volumes. The composite distribution of technically recoverable volumes must be determined by stochastically adding together the recoverable volume distributions of each zone, while allowing for the fact that, in any given realization, one or more zones may geologically fail, and the successful zones may comprise a mixture of oil and gas zones. Frequently, the composite, technically recoverable volume distribution is then used as a starting point to determine the economic value of the prospect, under the assumption that the prospect can be treated as if it were a single zone.
In this paper we carry out a full stochastic economic analysis of a typical multi-zone, deepwater exploration prospect in the Gulf of Mexico, and contrast this with the results of a simplified analysis in which it is assumed that the composite technically recoverable volume has been found in a single zone. This simplifying assumption can lead to inaccuracies and inconsistencies in the economic analysis. In the full multi-zone case it is quite possible that the stacked zones are composed of a mixture of oil and gas zones. This can only be treated in the simplified case by assuming that costs are largely independent of the hydrocarbon type and mix. In the full analysis the mixed oil and gas case can be handled robustly. We have also found that the simplifying assumption of a single zone can lead to a significant underestimation of the number of wells required to develop a prospect. This, in turn, leads to overoptimistic economics.
Valuation of Technology and Information for Reservoir Risk Management
Authors: Raghuraman B. , Couet B. , Savundararaj P. 
Published: December 2007

Abstract
Reservoir risk management involves optimizing assets given inherent reservoir uncertainties and minimizing risk by reducing these uncertainties. The decision to implement any reservoir management technology is usually based on a cost-benefit analysis. Consequently, the correct valuation of valueadding technology (often based on net present value) becomes a significant part of a reservoir management process. A crucial underlying factor in such an analysis is the uncertainty in the reservoir model and its properties, and in the financial variables associated with the asset. The former includes, for example, uncertainty in properties such as reservoir geometry or permeability in the reservoir, while the latter refers to uncertainty in financial parameters such as discount rate or hydrocarbon price.
This paper discusses techniques for valuation of technology and information related to reservoir risk management. For demonstration purposes, these techniques are applied to valuation of real-time control and monitoring technologies in a reservoir with multiple uncertainties in its physical properties. Because of the presence of these uncertainties, value quantification requires a stochastic optimization of the reservoir production strategy, where the objective function includes a risk-aversion factor. By applying these techniques one can generate a decision-making table that shows the benefit of implementing a technology at various confidence levels. One can then further extend the analysis to estimate the added value to the reservoir if the uncertainties were to be reduced (or even eliminated) by implementing appropriate monitoring technologies. This process enables quantification of the value of information and is useful in designing monitoring strategies.
Such techniques are applicable in cost-benefit analysis and other decision-making activities for both a deterministic and a stochastic approach to reservoir management. They can therefore be used as tools for the valuation, pricing, and marketing of technology.
Geostatistical History Matching Under Training-Image Based Geological Model Constraints
Authors: Caers Jef 
Published: December 2007

Abstract
History matching forms an integral part of the reservoir modeling work-flow process. Despite the existence of many history matching tools, the integration of production data with seismic and geological continuity data remains a challenge. Geostatistical tools exists for integrating large scale seismic and fine scale well/core data. A general framework for integrating production data with diverse types of geological/structural data is largely lacking. In this paper we develop a new method for history matching that can account for production data constraint by prior geological data, such as the presence of channels, fractures or shale lenses. With multiple-point (mp) geostatistics prior information about geological patterns is carried by training images from which geological structures are borrowed then anchored to the subsurface data. A simple Markov chain iteratively modifies the mp geostatistical realizations until history match. The method is simple and general in the sense that the procedure can be applied to any type of geological environment without requiring a modification of the algorithm.
Microseismic Imaging of Hydraulic Fracture Complexity in the Barnett Shale
Authors: Maxwell S. C. , Urbancic T. I. , Steinsberger N. , Zinno R. 
Published: December 2007

Abstract
Microseismic monitoring has been used to image hydraulic fracture growth in the Barnett Shale. The Barnett is a naturally fractured shale reservoir, which causes significant complexity in fracture growth during well stimulation operations. Several Barnett treatments have been successfully imaged between March 2000 and December 2001. In this paper, examples will be given to illustrate the complexity and variability which is developed during the treatment as the slurry interacts with the pre-existing fracture sets. The microseismic images explain why the stimulations occasionally grow at an angle to the assumed fracture orientation and into neighboring wells. Differences in production rates from various wells could also be related to the fracture geometry. The implications of the images to reservoir management highlight the benefit of imaging individual fracture networks to avoid overlapping and for targeting potential new well locations.
A Practical Guide to Hydraulic Fracture Diagnostic Technologies
Authors: Barree R. D. , Fisher M. K. , Woodroof R. A. 
Published: December 2007

Abstract
Hydraulic fracturing is key to the economic success of many oil and gas fields around the world and has improved production in low permeability reservoirs for more than 50 years. Successful stimulations are engineered to place the proper type and volume of slurry based on estimating the dimensions of the optimal fracture to be created in a specific wellbore. Several commonly used technologies are available which determine important fracture parameters such as fracture dimensions, fracture orientation, fracture conductivity and proppant placement effectiveness. Fracture models are today's most widely used tool to predict the optimal frac geometry based on conditional inputs such as closure stress, pore pressure, permeability, fluid saturation and numerous other mechanical and petrophysical properties of the reservoir. In many cases, these parameters are based on assumptions rather than hard data, and incorrect assumptions then lead to sub-optimal stimulation results.
Direct near-wellbore diagnostics such as radioactive tracers and temperature logging are often used to gather information about fracture height and proppant placement effectiveness, while direct far-field diagnostics such as tiltmapping and microseismic fracture mapping are used to determine hydraulic fracture dimensions and orientation.
Direct fracture diagnostics alone only tell the story of what happened after the fact on a given well, but they can also be used to build a calibrated fracture model which accurately predicts fracture growth in a reservoir. Depending upon the critical information needed for specific fracture stimulation, one or more diagnostic tools may be applied. These diagnostic tools will be discussed and compared in order to provide a reference of widely used diagnostic tools with strengths and limitations discussed along with examples of each in use in fracture optimization.
Wettability Alteration of Diatomite Induced by Hot-Fluid Injection
Authors: Tang Guo-Qing , Kovscek Anthony R. 
Published: December 2007

Abstract
A series of spontaneous water imbibition experiments in outcrop diatomite cores at elevated temperatures (up to 240ºC) and pressures (up to 600 psi) were conducted by employing a high-temperature and high-pressure coreholder that is scanned non-invasively using X-ray computed tomography (CT). The results show that temperature has a profound effect on oil recovery by spontaneous water imbibition from diatomite cores; the imbibition rate and oil recovery increase with temperature systematically.
This work analyzes the effect of temperature on water imbibition behavior using a simple analytical mathematical model. This model proposed is based on the concept of imbibition potential (Pim), which is defined as the slope of the line obtained when average water saturation is plotted versus square root of imbibition time. With this model, we are able to identify the effect of viscosity ratio, interfacial tension, and wettability (all are functions of temperature) on imbibition behavior at elevated temperatures. The experimental data indicate wettability alteration towards increased water-wetness plays an important role in improving oil recovery. Experimental observations indicate that the mechanism of wettability alteration in diatomite is related to detachment of fines from pore walls. Fines detachment with increasing temperature creates fresh water-wet pore surfaces thereby increasing spontaneous imbibition recovery.
A Comprehensive Reservoir Evaluation of a Shale Reservoir—The New Albany Shale
Authors: Zuber Michael D. , Williamson Jeron R. , Hill David G. , Sawyer Walter K. , Frantz Joseph H. 
Published: December 2007

Abstract
This paper presents the results of a comprehensive reservoir evaluation of the New Albany shale reservoir in northern Kentucky and southern Indiana and Illinois. Although initially compared with the Antrim shale in the Michigan basin, the New Albany shale has been found to have very different production characteristics than the Antrim. This paper presents the results of a comprehensive study performed on behalf of the New Albany Shale Producibility Consortium (NASPC). The objectives of this study were to determine the controls on production characteristics of wells in the New Albany shale, understand well reserves, and ascertain the potential for future development in the play. The reservoir evaluation included all available geologic, formation evaluation, production, and reservoir data from multiple fields within the play. During this study, core testing was conducted to develop baseline properties required for reservoir evaluation.
Study results indicated that fracture characteristics within the play are the key driver for well production characteristics and reserves. In addition, we found that matrix gas porosity, bulk permeability, methane adsorption characteristics, and net pay thickness also differentiate the New Albany shale reservoir from the Antrim. The results also indicated that horizontal wells may have the potential to improve productivity and reserves within the play by specifically targeting the characteristics of the fracture pattern within the reservoir.
The results of this paper may be useful to producers in fractured shale plays who wish to improve their understanding of flow characteristics and well performance. The work presented in this paper is important because it increases the knowledge base of shale reservoir properties and characteristics and because it describes an approach that can be used to characterize shale reservoirs.
Identification of Unknown Permeability Trends from History Matching of Production Data
Authors: Grimstad Alv-Arne , Mannseth Trond , Aanonsen Sigurd Ivar , Aavatsmark Ivar , Cominelli Alberto , Mantica Stefano 
Published: December 2007

Abstract
We investigate into how a priori unknown large-scale permeability structures like channels/barriers can be identified from history matching of production data, using Adaptive Multiscale Estimation (AME).
With Multiscale Estimation (ME) of the permeability, we solve a sequence of parameter estimation problems with increasing resolution for the permeability until a match is obtained. With AME - and contrary to Ordinary Multiscale Estimation (OME) - the parameterization refinement is not the same all over the reservoir. We aim at introducing new degrees of freedom in the permeability parameterization only where it is warranted by the production data.
The paper describes the principles of AME, and extends AME to corner point grids on non-rectangular 2D reservoirs. On 2D synthetic examples, we demonstrate how AME is able to completely identify simply shaped large-scale permeability trends, and how it avoids over-parameterization where OME does not.
On 2D field examples, AME is found to identify large-scale trends. When the large-scale trend has a more complex shape, AME identifies a similar trend of less complex shape at approximately the same location. The identification of the permeability trends for the field examples can, however, be improved upon, and, e.g., use of coarsening (as well as refinement) in the parameterization selection will be further considered in future work.
Determination of OHIP and Aquifer Constant Without Prior Knowledge of Aquifer Models
Authors: Bhuiyan Mofazzal H. , Chamorro Alexander , Sachdeva Rajesh 
Published: December 2007

Abstract
This paper outlines a new technique to determine original hydrocarbon in place (OHIP) and aquifer influx constant from production and pressure history. The Hsieh et al 1.method was modified and extended in many significant respects. With the new technique, calculations can be done using either the conventional (CMBE) or general material balance equation (GMBE). The proposed method thus applies to any fluid type (gas, oil, gas condensate, volatile oil etc.). This method does not require any pre-selection of aquifer models, and it can still calculate aquifer constant, water influx quantities and OHIP values. A computer algorithm was developed to take the "subjectivity" out of the Hsieh et. al. method. The new technique was successfully verified using numerous real-life examples that involved different reservoir types. The method was incorporated and tested using the commercially available material balance program2 (OilWatTM / GasWat™)1#.
A Neural Network Model for Prediction of Liquid Holdup in Two-Phase Horizontal Flow
Authors: Shippen Mack E. , Scott Stuart L. 
Published: December 2007

Abstract
Accurate prediction of liquid holdup associated with multiphase flow is a critical element in the design and operation of modern production systems. This prediction is made difficult by the complexity of the distribution of the phases and the wide range of fluid properties encountered in production operations. Consequently, the performance of existing correlations is often inadequate in terms of desired accuracy and range of application. This investigation focuses on the development of a neural network model, a relatively new approach that has been successfully applied to a variety of complex engineering problems. Data from five independent studies were used to develop a neural network for predicting liquid holdup in two-phase horizontal flow. A detailed comparison with existing empirical correlations and mechanistic models reveals that the neural network model shows an improvement in overall accuracy and performs more consistently across the range of liquid holdup and flow patterns.