bluuebunny/crossref_metadata_2025_split huggingface dataset:
Visual Observation of Produced Water Re-Injection Under Laboratory Conditions
Authors: Al-Abduwani F. A. H. , van den Broek W. M. G. T. , Currie P. K. 
Published: December 2007

Abstract
Produced water re-injection is one of the most attractive produced water disposal methods both economically and environmentally, especially for offshore rigs. However, the main problem associated with PWRI is the unpredictable nature of injectivity decline.
In this paper a few of the basic experimental techniques used in assessing the damage inflicted upon sandstone samples are reviewed. Also a new experimental design is proposed, that is believed to add further insight to the ongoing research in this topic.
Water Shut Off in Gas Wells: Is there Scope for a Chemical Treatment?
Authors: Ligthelm D. J. 
Published: December 2007

Abstract
Water producing gas wells may suffer from liquid loading and get killed or their water production may exceed the capacity of the water handling facilities. Just closing off the water producing zone may be unacceptable if they have a large contribution to the gas production. A near well bore chemical treatment using a polymer solution is an option to reduce the water production and maintain the gas production. Once adsorbed to reservoir rock, the polymer may significantly reduce the relative permeability to water in the near well bore area.
Hundreds of gas wells of the Nederlandse Aardolie Maatschappij (The Netherlands) suffer from water production. A simulation study using a radial single well model was carried out to look after the feasibility of a treatment.
The study shows that a treatment based on reduction of the water relative permeability causes a choke effect: both the water and gas flow rates are reduced instead of only the water rate. Moreover, the benefits of a treatment are tempered because of a clean-up effect after injection of the chemicals. A reduction in the water/gas ratio by a factor 2 requires a reduction in the water relative permeability by at least a factor 10.
A well which was killed due to liquid loading at a high water/gas ratio and with a high contribution to the gas production by the water producing interval is a suitable candidate for treatment.
A treatment may also be considered for a well of which the water production exceeds the capacity of the water handling facilities. Provided that the flowing tubing head pressure can be significantly lowered, the loss of gas production from the water producing zone can be compensated by increased gas production from the other intervals.
A Pore-Network Model of In-Situ Combustion in Porous Media
Authors: Lu Chuan , Yortsos Yannis C. 
Published: December 2007

Abstract
In-situ combustion in porous media find applications in a variety of problems. Existing models to date are based on a continuum description, in which effective porous media are used. In this paper, we consider the use of dual pore networks (pores and solid sites) for modeling the effect of the microstructure on combustion processes in porous media. The model accounts for flow and transport of the gas phase in the porespace, where convection predominates, and for heat transfer by conduction in the solid phase. Gas phase flow in the pores and throats is governed by Darcy's law. Heterogeneous combustion with one-step finite kinetics is assumed at the pore walls. The time-dependent problem is solved numerically using a fully implicit scheme. The validity of the model is tested against existing 1-D solutions, in which three types of combustion patterns arise, depending on the value of a dimensionless parameter related to the ratio of heat capacities. Then, we report on 2-D simulations for forward combustion. The development of sustained front propagation is studied as a function of various parameters, which include heat losses, instabilities, a correlated porespace and the distribution of fuel. Implications of the findings for continuum models are discussed.
A New Modeling Approach for Heavy Oil Flow in Porous Media
Authors: Kamp A. M. , Joseph D. D. , Bai R. 
Published: December 2007

Abstract
Typical gas relative permeability measured during primary depletion of sand packs filled with heavy oil is in the order of 1E-6 - 1E-5. This is much lower than what is found in similar experiments with light oil. We think that the reason for this difference is that in heavy oil depletion, free gas flows in the form of small bubbles (dispersed flow) and not as connected gas. For dispersed flow, the velocity of the gas phase would not be inversely proportional to the gas viscosity, as would result from applying conventional Darcy's law.
This discrepancy indicates that a different type of model might be needed. We suggest the use of effective phase viscosities that should replace the relative permeabilities. We study a special case, in which the velocities of oil and gas are supposed to be equal. This leads to a model with one continuity equation and a Darcy law for the gas-oil mixture, depending on one effective viscosity.
We solve the model for steady flow in a core, obtaining good agreement with experimental measurements. Matching experimental data, an expression for the effective viscosity is obtained. The model is a first step in an attempt to obtain a new model for viscous gas-liquid flows in porous media. Such a model would reduce the uncertainty in forecasts of the oil production and recovery factors in heavy oil reservoirs such as the Venezuelan Orinoco belt.
Quantitative Analysis of Deliverability, Decline Curve, and Pressure Tests in CO2 Rich Reservoirs
Authors: Jokhio Sarfraz A. , Tiab Djebbar , Escobar Freddy H. 
Published: December 2007

Abstract
This paper investigates the effect of higher concentrations (0- 100%) of CO2, H2S, and N2 on natural gas well deliverability, reserve estimation, and pressure test analysis quantitatively. Physical properties of natural gases such as viscosity and compressibility are corrected according to the concentrations of the contaminant gases such as CO2, N2, and H2S present in it. These contaminant gases have profound impact on pressure test analysis. The Carr et all1 viscosity correction chart allows adjusting the viscosity up to 15% concentration of these contaminant gases. However, Wichert and Aziz2 compressibility correction chart allows up to 80% concentration of the CO2 and H2S.
Tiab3 developed an analytical method to estimate pseudopressure function for 0-100% combined-concentration of CO2, H2S, and N2. His pseudopressure was first re-plotted to simplify the procedure and then it was used to analyze the deliverability, pressure tests, and decline curves quantitatively. The analysis was performed with Carr et all1 viscosity correction chart, pure CO2 properties, and then with Tiab’s corrected pseudopressure. Pure CO2 properties were used due to the fact that the sample data has 98.256% CO2.
During this study it was observed that the compressibility factor has a little effect on analysis since it is a volume- related property. Viscosity, however, has the largest effect on the analysis since pressure is transmitted through the fluid in the porous media and viscosity works against it. It was also observed that the numerical method of calculating pseudopressure function introduced successive error in the analysis. Number of pressure data points also contributed to the error in numerical integration of the pseudo- pressure function.
Analysis of field as well as simulated examples resulted an absolute error range of 13-75% in the permeability estimation in pressure tests, 77% in deliverability tests, and 20-95% with pressure derivative. Error in AOF was observed as 15% and as high as 32 % in reserve estimation.
Paraffin-Crystal-Modifier Studies in Field and Laboratory
Authors: Becker J. R. 
Published: December 2007

Abstract
Crystal modifier chemistry is fast becoming very important in the enhanced production capacity of crude oil fluids. These products have been used for many years in offshore and refinery applications with a high degree of success. However, the broad usage of these chemicals in production areas has been spotty at best and often underutilized. Because of the incentive of increased fluid production resulting from crystal modifier application, producers have been more receptive to the usage of these types of treatment chemical applications. Considering this increased willingness of producers to incorporate these chemicals in their treating chemical programs it was important to study the various application methods by which these products can be introduced into the systems requiring treatment. Since, not all wells are equipped with capillary injection strings, or have backside access to chemical injection other methods such as squeeze applications are considered. Thus, laboratory testing and field test results are discussed in this paper.
Applications of the Transient Hyperbolic Exponent
Authors: Spivey J. P. , Frantz J. H. , Williamson J. R. , Sawyer W. K. 
Published: December 2007

Abstract
This paper introduces the concept of the transient hyperbolic exponent b. The transient hyperbolic exponent may be used to derive values for b for use in Arps' equations for a variety of drive mechanisms. For a coalbed methane reservoir, b is shown to be a function of the ratio of the average reservoir pressure to the Langmuir pressure, with b approaching 1.5 at pressures much higher than pL, 1.0 when the pressure is equal to pL, and approaching 0.5 at pressures much lower than pL. For wells producing from finite, transient dual porosity reservoirs, the b value may be as high as 2, during a flow period characterized by steady state flow in the natural fracture system, and transient linear flow in the matrix. A coalbed methane well and two Antrim Shale wells are presented as examples.
Neural Network Analysis Identifies Production Enhancement Opportunities in the Kaybob Field
Authors: McNichol Joanne L. , Getzlaf Don A. , Protz Myron 
Published: December 2007

Abstract
Evaluating and optimizing well completion procedures can be difficult because of the complexity of reservoir and completion dynamics. Although a vast amount of data is available within the industry, we need to analyze this data to enhance our ability to improve well economics. In this paper, we discuss the use of an artificial neural network (ANN) as a tool to evaluate and optimize stimulation methods and to develop a prediction model for three specific producing formations in the Kaybob field of northwestern Alberta, Canada.
The area is gas prone, with multiple producing horizons. Significant amounts of gas have been produced from the Bluesky, Cadomin, and Gething formations. Permeability is typically low, and hydraulic fracturing is required for economic production. Fracture treatment designs have varied considerably, with no apparent consensus as to the optimum fracturing fluid, proppant type, or treatment volume.
Log Examples with a Prototype Three-Detector Pulsed-Neutron System for Measurement of Cased-Hole Neutron and Density Porosities
Authors: Odom Richard C. , Wilson Robert D. , Ladtkow Richard K. 
Published: December 2007

Abstract
Recent publications1,2,3,4,5 have described the development and utility of cased-hole neutron and density porosity measurements from a pulsed-neutron system. Porosity information from cased-hole logging can provide required data for wells with limited logging programs such as old wells or new wells where open-hole logging is not viable. In reservoir sequences typical of the Rocky Mountain region, the addition of the cased-hole density measurement has proven useful in discriminating tight porosity from gas-filled porosity and coals from shales.
Whereas a tool such as the Computalog PND-S™ pulsed-neutron system uses two detectors, analysis of pulsed-neutron density measurement physics immediately suggests that a third long-spaced detector would be helpful in measuring deeper into the formation. Thus, a prototypical system based on the standard PND-S™ was constructed with a third detector at a 95-cm spacing. This prototype provided a collection of third detector data on normal logging runs.
Log examples from the North America Rocky Mountain region demonstrate the utility of this measurement in cased-reservoir analysis.
The Effect of Fracture Conductivity and Fracture Storativity on Relative Permeability in Dual Porosity Reservoir
Authors: Ahriche Imed , Tiab Djebbar 
Published: December 2007

Abstract
Relative permeability is one of the most significant parameters used in reservoir engineering simulation. It has been extensively investigated in homogeneous porous media. However, research on relative permeability in naturally fractured reservoirs is still limited. Because of laboratory limitations, simulation of naturally fractured reservoirs uses zero matrix-fracture capillary pressure, linear relative permeability with saturation, and neglects the effect of fracture conductivity and fracture storativity. The main objective of this study is to investigate the effect of these two parameters on relative permeability in naturally fractured reservoirs.
Single fracture system is made with different fracture characteristics such as porosity, permeability and fracture width using saw-cut Berea sandstone core samples with metallic plates. The centrifuge method is used to determine water-oil capillary pressure and relative permeability. For water-gas measurements, the parallel plate method is used.
Capillary pressure and relative permeability curves for different models were obtained and analyzed. A representative correlation between fracture absolute permeability and fracture aperture is obtained. The effect of dual porosity is well observed on the capillary pressure and relative permeability curves for both oil-water and gas-water systems. Thus, both capillary and viscous forces dominate the displacement of fluids in naturally fractured reservoirs. Fracture storativity has a negligible effect on the relative permeability as compared tofracture conductivity effect.
Combining Gradual Deformation and Upscaling Techniques for Direct Conditioning of Fine Scale Reservoir Models to Dynamic Data
Authors: Mezghani Mokhlès , Roggero Frédéric 
Published: December 2007

Abstract
Integration of dynamic data typically requires the solution of an inverse problem that can be computationally intensive and practically infeasible for fine scale reservoir models. In this paper we present a new methodology to directly update fine scale geostatistically-based reservoir models by combining gradual deformation parameterization for the fine scale geostatistical model and an upscaling technique for the coarse scale flow simulation model.
The proposed methodology includes:
Perturbation of the fine scale geostatistical model using the gradual deformation parameterization. Gradual deformation ensures the preservation of the overall geostatistical properties of the fine model. Generation of the coarse scale flow simulation model by upscaling the fine scale geostatistical model. Sensitivity computation of the flow simulation results with respect to the fine scale parameterization. This sensitivity computation is analytical and takes into account the upscaling process. Direct updating of the fine scale geostatistical model using classical optimization process. Direct updating ensures consistency between the fine and coarse scale models.
The accuracy of the proposed methodology was improved by calibrating the flow simulation model. The objective of this calibration is to reduce the error introduced by the upscaling step during the flow simulation.
We applied successfully our methodology for fine scale reservoir description by integrating permanent down-hole gauge measurements directly into a three-dimensional geostatistical model containing about two million grid blocks. This test is designed to highlight several key issues of the proposed methodology:
Efficiency of the upscaling step coupled with gradient-based optimization to speed up the history matching process. Usefulness of the calibration step for a correct integration of upscaling techniques in history matching. Capability of the methodology for maintaining consistency and coherency between fine scale and coarse scale models. Improvement of the reservoir characterization by integrating dynamic data at the fine geostatistical scale.
We conclude that the proposed methodology can be used effectively and efficiently for reservoir characterization purposes.
Constraining Reservoir Facies Models to Dynamic Data - Impact of Spatial Distribution Uncertainty on Production Forecasts
Authors: Zabalza-Mezghani I. , Mezghani M. , Blanc G. 
Published: December 2007

Abstract
This paper presents a new approach to constrain reservoir facies models to dynamic data. This approach is mainly based on the combination of an optimization method called the simplex method and parameterization techniques such as the gradual deformation method.
This parameterization technique is well known for its efficiency in constraining geostatistical models to dynamic data. Originaly developped for continuous Gaussian models, the gradual deformation method was extended to facies models [12] and more recently to any kind of geostatistical model. However, the numerical behavior of the inversion can be strongly affected by discontinuities in the model changes in case of facies-based models. Our approach proposes a robust inversion method coupled with the gradual deformation method for the calibration of facies models.
The methodology we present is directly inspired by the construction of a reservoir facies model. We start by generating a related Gaussian continuous geostatistical model. In a second phase this continuous model is transformed according to the number of facies and their proportions to obtain a consistent facies model. Since a direct parameterization of the facies model does not allow the preservation of the geological properties of the model, we perform the parameterization on the related continuous model and then we proceed to the model truncation. In this manner, we can optimize the deformation parameters involved in the parameterization using the simplex method to obtain an history match.
The efficiency of this approach is illustrated by matching an interference test. The parameterization phase was performed using the gradual deformation method. Constrained facies models were thus obtained.
A second phase of this study was devoted to quantifying the impact of uncertainty of spatial facies distribution on production forecasts. In an integrated process, we combine the simplex approach with experimental design theory and the joint modeling technique to achieve a probabilistic production forecast which takes into account the uncertainty on spatial facies distribution and classical reservoir parameters while preserving the history match. This application demonstrates the importance of the interference test matching in reducing the uncertainties on production forecasts.
Adding Value to Impedance Models through Sequence Stratigraphy
Authors: Marzuki Z. , Sams M. S. , Atkins D. 
Published: December 2007

Abstract
Impedance models should be more than just the inversion of seismic data, they should result from the integration of data from diverse sources. This integration adds value to the impedance model by increasing the information content and interpretability of the various data. The integration of geological, geophysical and other data measured in the different domains of time and depth is often not straightforward. One solution is to integrate the data within a common sequence stratigraphic framework.
A case study from a maturing oil field shows how this approach can lead to the improved understanding of the distribution of fluids and reservoir properties. An initial sequence stratigraphic framework was derived from the best quality well log data and preliminary seismic inversion results. This framework was used to guide the conditioning and integration of the all the well log data. As more well log data were integrated, improvements in wavelet estimation and seismic inversion were achieved. The initial framework was refined as the data demanded. The final result was an impedance model in time and depth consistent with the seismic data, the well log data and the geological interpretation.
The development of the most productive interval in the field had previously been based on the assumption that vertical connectivity existed between the different sands within it. Although recent drilling has disproved this assumption and indicated vertical barriers to fluid flow, these could not be imaged using conventional analysis of reflection seismic data. Using the sequence stratigraphic framework to extract impedance values, the separate sand layers could be imaged. These extractions also confirmed that hydrocarbons in an unperforated sand had not yet been depleted and allowed new development drilling locations to be selected.
Subsea Mudlift Drilling: Planning and Preparation for the First Subsea Field Test of a Full-Scale Dual Gradient Drilling System at Green Canyon 136, Gulf of Mexico
Authors: Schumacher J. P. , Dowell J. D. , Ribbeck L. R. , Eggemeyer J. C. 
Published: December 2007

Abstract
Currently the deepwater drilling industry uses single gradient drilling: one single mud weight from the surface to total depth (TD) to control the thin margins between fracture gradient and pore pressure gradient. In this conventional system, a single mud column extends from the rig floor to TD, resulting in a hydrostatic bottomhole pressure. Pore, fracture and mud pressure gradients are referenced to the rig floor.
Dual Gradient Drilling (DGD) provides the same bottomhole pressure with a combination of two fluid gradients: slightly heavier mud from the mudline to TD, and seawater from the mudline back up to the rig floor. All gradients are referenced to the mudline rather than the rig floor. With DGD, the margins between fracture gradient and pore pressure are significantly greater while drilling the well.
The benefits of a dual density system are well documented, but in general, lower cost wells can be drilled more safely and with more completion flexibility than with single gradient systems. Since 1996, the SubSea MudLift Drilling (SMD) Joint Industry Project (JIP) has been developing a dual gradient drilling system and all the associated drilling and well control techniques and procedures.
This paper is the second in a series of papers presented on SMD technology (see SPE 71357 and SPE 71359). It describes the planning and preparation for the world's first dual gradient well. The well will be a partnership collaboration between Texaco, Diamond Offshore and the SMD JIP. It is a Gulf of Mexico Green Canyon well test in a water depth of 910-ft (Figure 1). This location has an intermediate water depth with a known pore pressure environment. It provides an excellent opportunity for extensive testing prior to the final development and delivery of a dual gradient drilling system for use in ultra-deepwater (beyond 6000 ft).