bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Evaluation of Procedures to Estimate Uncertainty in Hydrocarbon Recovery Predictions
Authors: Chewaroungroaj Jirawat , Varela Omar J. , Lake Larry W. 
Published: December 2007

Abstract
It is widely recognized that predictions of hydrocarbon recovery are uncertain. In the area of reservoir engineering, the sources of uncertainty have three major causes: 1) the model, because it is an imperfect representation of reality, 2) geologic parameters, because of a limited sampling in space and/or time, and 3) measurement errors in the experiments performed to determine inputs. Thus, a statistical treatment that recognizes both the lack of knowledge and the uncertainty of the parameters involved in the forecast of reservoir performance is desirable. Current stochastic-modeling approaches (Monte Carlo simulation and geostatistics) require extensive computational effort for realistic problems. There are numerous reasons for this, but the one that seems to present the largest hurdle is that reservoir predictions require a large number of input parameters. The thrust of this work is to find ways to perform uncertainty predictions with fewer parameters.
This paper demonstrates several approaches that quantitatively estimate uncertainty in specific hydrocarbon-recovery predictions. These approaches include scaling, firstorder and second-order analyses, response surface, and the Taguchi and Box-Behnken experimental designs. Numerical reservoir simulations were performed in two hypothetical reservoirs using each of the above methods to estimate uncertainty in oil-recovery efficiency. Results from these techniques are compared to experimental design and Monte Carlo simulations. The combination of scaling and the Box-Behnken experimental design can provide a reasonably accurate uncertainty estimation of hydrocarbon recovery with fewer simulation runs than the Monte Carlo simulation. In addition, we successfully reduced the turnaround time of the Monte Carlo simulation runs by using clusters in parallel of personal computers instead of one computer (e.g., more than 10 times faster with a cluster of 16 PCs).
Experimental design and the use of multiple processors will reduce the computational effort in estimating uncertainty of a hydrocarbon-recovery prediction. This combination would also give rise to the possibility of exploring several existing methods in the design of experiments to lessen the burden of performing numerous large reservoir simulations.
Compaction of Argillaceous and Coarse-Grained Sediments
Authors: Rieke Herman H. , Chilingar George V. , Fertl Walter H. 
Published: December 2007

Abstract
During the past quarter century, the exploitation of oil and gas reserves, associated with thick sequences of very fine-grained and coarse-grained rocks in Tertiary basins, have become increasingly important for fulfilling the world's energy needs. Many exploration and reservoir development problems have arisen which demand an analytical solution. The scientific problems have arisen which demand an analytical solution. The scientific and technological problems associated with these geologically young basin sediments include the origin, maintenance and distribution of abnormally high pore-fluid pressures, chemical changes induced in the interstitial water by compaction, origin and migration of hydrocarbons, temperature gradients, clay minerals phase changes and subsidence of the surface. Successful drilling to depths greater than 20,000 feet in these sediments and the amounts of the hydrocarbons discovered and produced depend to a great extent on our knowledge of the physical and mechanical properties and deformation characteristics of the sediments and the interrelationships between their various petrophysical and fluid properties. This paper is an historical review of studies dealing with the effects that gravitational compaction of sediments has on hydrocarbon reservoirs and source beds. Specific attention will be given to the generation of abnormal pore-fluid pressures, chemistry of interstitial fluids, compaction models, pressures, chemistry of interstitial fluids, compaction models, compressibility of the reservoir rocks and surface subsidence.

Introduction
It has been postulated that gravitational compaction of sediments is directly related to the following parameters and can be functionally represented in the following manner:
C = (1)
Where C is the degree of compaction, is the stress on the sediment system, is the velocity parameter for solids and interstitial fluids in the system, is the density, is the bulk volume of the sediments, is the porosity, is the permeability of the system, is the burial depth, t is the time, T is the geothermal temperature, and c represents the compressibility relationships.
Gravitational compaction of sediments under the influence of their own weight has long been a recognized geologic phenomenon. In the seventeenth century Steno attributed variations in the attitude of sedimentary formations to compaction.
Sequential Scale-Up of Relative Permeabilities
Authors: Suzuki K. , Hewett T. A. 
Published: December 2007

Abstract
This paper presents a new method for scaling up multiphase flow properties which properly accounts for boundary conditions on the upscaled cell. The scale-up proposed does not require the simulation of a complete finely-gridded model. Instead it introduces assumptions allowing the calculation of the boundary conditions related to each block being scaled up.
To upscale a coarse block, we have to assume or determine the proper boundary conditions for that coarse block. To date, most scale-up methods have been based on oversimplified assumptions such as steady-state flow associated with uniform fractional flows over all the boundaries of the coarse block. However, such an assumption is not strictly valid when we consider heterogeneities.
The concept of injection tubes is adopted: these are hypothetical streamtubes connecting the injection wellbore to all inlet faces of the fine grid cells constituting the block to be scaled up. Injection tubes allow the capturing of the fine-scale flow behavior of a finely-gridded model at the inlet face of the coarse block without having to simulate the full fine grid. We describe how to scale up an entire finely-gridded model sequentially using injection tubes to determine the boundary conditions for two-phase flow.
This new scale-up method is able to provide a coarsely gridded model which can reproduce the spatially-averaged performance of the finely-gridded model reasonably accurately. The method has been shown to be applicable not only to viscous-dominated flow but also to flow affected by gravity for reasonable viscous-to-gravity ratios.
Historical Problems with Old Field Rejuvenation
Authors: Blaskovich F. T. 
Published: December 2007

AbstractIn many parts of the world, the redevelopment of older fields presents unique problems that will require innovative solutions. With the rising costs of finding and developing new oil fields, oil companies are turning more attention to revitalizing existing fields. Because of historical practices, these fields often have significant potential for enhanced recovery. These older fields have many different problems to deal with than the more modern fields that traditionally drive petroleum technology.Advances in computer hardware and software technology have made it possible to analyze reservoirs at a level of detail unimagined only a few years ago. With all of this power on our desktops, it is easy to lose sight of a major problem in dealing with older fields – the historical data.In many cases, there may be a large amount of historical data, but much of it is either inaccurate or critical types of data have not been gathered. Several field examples are discussed in this paper. Each field has redevelopment potential using modern techniques, but each project has great uncertainty due to data constraints. The conclusions and recommendations of the paper include suggestions for ways to solve these problems. Since we cannot go back in time to gather critical missing data (e.g., early production and injection data, initial fluid properties, produced compositions, etc.), special techniques will be needed to determine the value of these projects.
Using Crosshole Electromagnetics (EM) for Reservoir Characterization and Waterflood Monitoring
Authors: Patzek Tadeusz , Wilt Michael , Hoversten G. M. 
Published: December 2007

Abstract
The crosshole EM technique provides an image analogous to a smoothed two-dimensional induction resistivity log. Inductive EM sources are placed in one well and magnetic field receivers in a second well, up to a km away. Sources and receivers are positioned above within and below the depth interval of interest, and we image the resistivity of the interwell volume to fit the collected data. Data may be collected in open and/or steel-cased boreholes, although steel casing reduces this range. The resolution of images is roughly 5 percent of the well spacing.
The technique has been used for more than 5 years in imaging thermal oil recovery operations, but more recently for reservoir characterization and water flood imaging. The resistivity contrast between salt water saturated zones and oil and gas pay zones usually provides an excellent signal for the EM data and makes the imaging of the water flood fairly straightforward.
In this paper we provide a technology overview and then show a case history where the EM resistivity images have defined the initial water saturation distribution, and have tracked changes over a two year period due to water flooding in a fracture dominated southern California reservoir. We further describe simulations for crosshole EM imaging in carbonates for a WAG (water alternating gas) process where the technique is used for initial site characterization and to monitor saturation changes during the injection.
Technology Integration of Conformance and Magnetic Resonance Imaging Enhances Stimulation Treatment
Authors: Soliman M. Y. , Creel Prentice , Rester Stephen , Sigal Richard , Haest James , Azari Mehdi 
Published: December 2007

Abstract
Although fracturing is an established technology with a wide range of usage, certain reservoir scenarios that appear to be good candidates for its application do not benefit from its usage. Examples of these reservoirs include stratified wells in which some of the layers are water-bearing formations or scenarios where an aquifer is present and the fear of breaking into the water zone exists.
By combining the techniques developed in the magnetic resonance imaging (MRI) and conformance technologies, accurate identification of reservoir conditions can be made, and a fracturing approach that can enhance oil production and reduce or even eliminate water production can then be designed and successfully implemented.
The success of this approach depends on several factors. The first is an accurate description of the reservoir. Without this, it is not be possible to accurately assess the underlying reasons for the water production problems so that the appropriate stimulation design or remedial treatment can be applied.
The importance of using the proper diagnostic tools and techniques is, therefore, of extreme importance when determining what remedial applications should be considered. These tools must determine the type and the location of reservoir fluids as well as whether the encountered water is mobile. Presently, only one technology, MRI, can fulfill all these needs. The tool developed to target this technology is an openhole MRI logging tool that operates on magnetic resonance imaging principles. This tool plays a major role in the successful application of conformance technology.
This paper provides an in-depth discussion on how the concept of coupling fracturing, conformance and MRI technology has been made possible through the application of MRI logs. Simulated examples, created using a commercially available 3-D, 3-phase numerical simulator, will be used to illustrate the technical enhancements and economic value that can be derived through use of this technological integration.
Actual field cases performed in the Permian Basin will be presented and discussed. The cases described in this paper show the extent of the technical and economical successes achieved using this technology.
New Methods for Determining Formation Properties from Stabilized and Unstabilized Gas-Well-Test Data
Authors: Satman Abdurrahman , Onur Mustafa , Tureyen Omer Inanc 
Published: December 2007

Abstract
In this paper, new explicit analytical equations for stabilized and transient deliverability coefficients in terms of formation/fluid parameters are presented. These equations are derived for fully and partially penetrating vertical wells and for fully penetrating horizontal wells. The proposed equations use the relationship between the empirical (Rawlins and Schellhardt) deliverability equation and rigorous (or Forechheimer's) deliverability equations for both stabilized and unstabilized (transient) flow conditions. Based on these new equations, we also present new methods for determining not only the performance coefficients, but also formation parameters from stabilized and transient gas deliverability data. Unlike the existing methods, our new methods do not require geometric mean of pressure or rate data. This is a distinct advantage of the methods presented in this paper over the existing methods because determination of geometric mean of pressure or rate data may be quite difficult, and the mean value is quite sensitive to the measurement errors in such data. Thus, the methods given in this paper should prove very useful for determining formation parameters accurately from deliverability tests in vertical and horizontal wells. The accuracy and applicability of the methods given in this study are verified by analyzing two test data published previously in the literature. Results are compared with those obtained from the existing methods in the literature and indicate that combination of our new methods with the Hinchman-Kazemi-Poettmann method for isochronal test types provides more information about the formation and reliable deliverability forecasting.
Use of Silicate Mud to Control Borehole Stability and Overpressured Gas Formations in Northeastern British Columbia
Authors: Stewart Michael R. , Kosich Bill , Warren Brent K. , Urquhart John C. , McDonald Michael James 
Published: December 2007

Abstract
A freshwater silicate based drilling fluid, containing 20-30% sodium silicate by volume, was successfully used to drill a gas well in northeastern British Columbia. Major drilling issues in the area include borehole instability in 500 plus meters of highly dispersible Ft. Simpson shale, high pressure gas zones and potential moderate-severe lost circulation.
Despite problems of severe lost circulation and high mud weights, the caliper log on the silicate well showed &lt;1% hole enlargement over the Ft. Simpson shale and 12% enlargement over the entire intermediate section. Typical offset calipers with other water-based muds average 48% and 31% enlargement over the Ft. Simpson and entire well section, respectively.
Rates of penetration with silicate mud were generally better than offset wells. Uphole formations drilled to 1060 meters with a low solids, lower density silicate fluid (1195 kg/m3 mud density) drilled at an average of 19.2 m/hr. Offsets drilled with gel-chemical or gel-PHPA systems over the same interval normally averaged 12.6 m/hr.
This paper describes the planning and drilling of the first well with a drilling fluid containing silicates up to 30% concentration. Topics discussed include borehole stability, rates-of-penetration, motor performance, drilling fluid stability and properties, and environmental aspects of silicate disposal.
A Permeability-Dependent Dimensionless Inflow Performance Relationship Curve for Unfractured Gas Wells
Authors: Billiter Travis , Lee John 
Published: December 2007

Abstract
A dimensionless inflow performance relationship (IPR) curve that is a function of permeability has been developed for unfractured gas wells. Both numerical and analytical methods were used to solve the non-Darcy, gas flow equations. This analysis showed that the current dimensionless IPR curve for unfractured gas wells in pseudosteady-state flow is basically independent of all relevant variables, except permeability. The proposed current dimensionless IPR curve has the same general form as the familiar Vogel dimensionless IPR curve for solution-gas-drive oil reservoirs, with the coefficients of the proposed dimensionless IPR curve being a function of permeability. The proposed current dimensionless IPR curve can be used to predict the deliverability of a gas well using a single-point test, as opposed to a standard four-point deliverability test, if the permeability of the well is known. A future dimensionless IPR curve to predict future gas well deliverability that is a function of permeability is also presented. The time to reach pseudo-steady state flow for an unfractured gas well is two to three multiples of the time predicted by the commonly used, stabilization time equation.
Gas-to-Liquids Technology for Bunyu Field, East Kalimantan, Indonesia
Authors: Arianto Indria Doria , Siallagan Charles P. 
Published: December 2007

Abstract
Technology to converts natural gas into synthetic liquid fuels (the name is GTL, for Gas-to-Liquids) turns unmarketable reserves of natural gas into a form that overcomes transportation costs. Synthetic liquid fuels produced via Fischer-Tropsch (FT) chemistry, such as gasoline, kerosene/jet fuel, and diesel, have long been known as the cleanest fuels in the world. Unfortunately, the cost making them has never been competitive when compared to conventional process. Now, because of better catalysts and process improvement, FT may have finally found a competitive niche. Bunyu Island located off the Northeast coast of East Kalimantan, Indonesia, approximately 580 km north and East of Balikpapan. There are 10 existing fields in Bunyu Island managed by Pertamina. Bunyu-Nibung field was discovered with the drilling of well BN-01 in 1971, geologic evaluation discovered oil and gas reserves. Until now, 15 wells had been drilled and developed as oilfield although the gas reserve is large. This gas reserve undeveloped because of the limitations of gas markets. Based on 22 MMscfd feed gas for 20 years production, this technology can converting gas to 4,180 b/d synthetic fuel consist of gasoline 1,797 b/d, kerosene 477 b/d, middle distillate 765 b/d, and HSD 1,053 b/d. Economic calculation indicates that this technology considered economically with POT 3.11 years and IRR 47.42%. Although it is too remote for economic transportation, GTL would liberate Bunyu-Nibung gas reserves from the limitations of gas markets.
Friction Factor in High-Pressure Gas Pipelines in the North Sea
Authors: Sletfjerding Elling , Gudmundsson Jon Steinar , Sjøen Karl 
Published: December 2007

Abstract
Field data from capacity tests of long-distance gas pipelines in the North Sea have been used to model the friction factor in internal coated pipelines. The field measurements were compared to an experimental investigation of the friction factor in coated pipes performed in a high-pressure flow loop. A good correlation between the experimental data and the field data was obtained. It was found that the friction factor in the coated gas pipelines could be modelled by the Colebrook-White correlation with an equivalent sand-grain roughness of 1.5 μm. The results showed that internal coatings effectively reduce the pressure drop in gas pipelines and thus increase the transport capacity.
Phase Behavior of PCB-Contaminated Natural Gas
Authors: Nor-Azlan N. , Adewumi M. A. 
Published: December 2007

Abstract
Polychlorinated-biphenyl (PCB) contamination problems are prevalent in the natural gas industry especially in the pipeline transmission and distribution sectors. As a result of PCB disposal problems, many natural gas companies have been subjected to heavy fines. Considering the magnitude of the problem, the gas industry has taken the initiative to pursue a comprehensive remediation effort to cleanup pipeline and distribution systems contaminated with PCB. This study is a part of the remediation effort. This paper addresses the phase behavior of PCB-contaminated natural gas systems and explores how to utilize this information to attempt the formulation of remediation strategies. A model suitably designed for studying the problem has been developed. The model is used to investigate the distributive nature of PCB compounds and to analyze their effects on the overall phase behavior of the natural gas system. New quality line definitions are introduced for the purpose of tracing PCBs in the gas mixture. Some experimental results and model predictions are presented and discussed. A case study using actual field natural gas mixture is performed in order to demonstrate the capability of the model prediction. The study is important in assisting engineers and operators to design an effective remediation strategy to cleanup pipeline transmission and distribution lines contaminated with PCBs.
Completion and Fracture Modeling of Low-Permeability Gas Sands in South Texas Enhanced by Magnetic Resonance and Sound Wave Technology
Authors: Fairhurst D. L. , Marfice J. P. , Seim M. R. , Norville M. A. 
Published: December 2007

Abstract
Recent advances in logging technology have enabled development of a better rock model and better fracture design for low-permeability reservoirs. The new measurements also have improved in-situ analysis and the identification of productive zones that might otherwise be bypassed.
Sonic waveform and magnetic resonance technology enhances the standard logging platform by providing a more accurate shear modulus and permeability estimate. The accuracy is necessary for a better dimensional fracture model. The model appears reasonable for completions in the Olmos and San Miguel sands in south Texas. In some cases the magnetic resonance has identified previously bypassed permeable streaks that increased production. In other cases, sonic waveform technology has helped determine fracture direction, thereby enhancing gas drainage and well placement.
In this paper, field production results are correlated to the model. Less efficient designs based on minimal data are compared with designs having more complete data sets. Recent completion data confirm that better parameters can be obtained with the new measurements.
Matrix Acidizing in Gas Wells
Authors: Fadele O. , Zhu D. , Hill A. D. 
Published: December 2007

Abstract
Matrix acidizing treatments are applied to gas wells to remove near-wellbore permeability impairment (formation damage). The acidizing process differs in gas wells compared with oil wells or water injection wells because of two-phase, gas-liquid flow during acid injection, and also because of the relatively low viscosity of the gas. This paper demonstrates how these differences affect the penetration of acid into the formation and the distribution of acid along the wellbore (acid placement).
When acid displaces gas in the formation around the wellbore, the favorable mobility ratio between the acid and the gas will lead to a piston-like displacement of the gas by the acid. However, behind the acid front, a residual gas saturation will remain. Our study shows that the impact of the residual gas saturation increases acid penetration into the reservoir, when compared with a single-phase displacement process.
The large contrast between the viscosity of the acid and the gas in the reservoir may be beneficial to a better distribution of acid along the wellbore. Because the acid is much more viscous than the gas, there will be an increased pressure drop wherever acid is placed in the formation. This can function as a natural viscous diversion - as acid enters the higher permeability zones, the increased pressure gradient can divert relatively more acid to lower permeability zones. We present modeling results that illustrate the magnitude of the viscous diversion effect in gas wells. This natural diversion precludes the use of gels or other viscous fluids for diversion in gas wells.