bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reservoir Monitoring and Characterization for Heavy-Oil Thermal Recovery
Authors: Pankaj P. , Pathak V. 
Published: December 2007

Abstract
Extracted post-stack seismic attributes from time-lapse 3-D seismic data have been used extensively to map steam areal conformance by using statistical analysis in the development and monitoring of follow-up processes.
A quantitative cross-calibration scheme between time-lapse seismic surveys has been developed using data normalization. It was found that a significant difference results from using a different calibration set; and that time-lapse data cross-calibration provides better, more stable and consistent results. Attributes from principal component decomposition of seismic data compensate for the redundancy of conventional seismic attributes in statistical analysis and provide better well-to-seismic ties when a full set of principal component attributes are used. Vertical steam conformance can be established through poststack inversion to provide 3-D visualization of the impact of lithologic control on steam distribution and steam migration pathway. The vertical conformance reveals that sequence architecture has a significant influence on steam migration. A sequence with high mud content tends to limit or slow both vertical and lateral migration of the steam chambers.
In pre-stack efforts, the functional relation of P- to S-wave velocities, called the mud-rock line, plays an important rule in extracting S-wave information from pre-stack data. With an optimized mud-rock line and high frequency seismic data, the inverted pseudo S-wave from AVO analysis has much higher resolution than the P-S wave data. The reservoir heterogeneity can be welldefined by fluid factor alone. The application of this technique to reservoir monitoring defines steam channels and identifies lithologic barriers within the reservoir.
Field Trials for Sonic Treatment of Natural Gas Storage Wells and Stripper Oil Wells for Well Remediation and Increased Productivity
Authors: Paulsen P. D. , Johnson D. O. , Edgar D. E. , Furness J. C. 
Published: December 2007

Abstract
The project team of Furness-Newburge, Inc., TechSavants, Inc. and Nicor Gas performed DOE sponsored research from 2000 through 2004 to develop a sonic tool to treat underground natural gas storage wells. One of the primary damage mechanisms for these wells is the formation of scale at the perforations or at the sand face through which the gas flows during gas injection and withdrawal. During well evaluation with backpressure tests (BPT) and multi-rate pressure transient tests (MRPTT), this blockage exhibits itself as a positive skin. The sonic treatment concept is to apply high intensity sound waves to help dissolve and break-up scale that forms at the perforations or the sand face and thereby improve gas/fluid flow.
After initial development of the prototype, the sonic tool was deployed in three separate natural gas storage wells in northern Illinois. The first deployment's purpose was to ensure that the sonic treatment did not damage the well. The second and third field deployments were used to evaluate the sonic treatment's ability to increase productivity as measured by BPT and MRPTT analyses. The second deployment, in a well with a negative skin prior to treatment, showed little or no increase in well productivity. The third deployment, in a well with measured scale damage prior to treatment, showed an increase in well productivity after sonic treatment. Specifically, the skin coefficient dropped from +2.5 to −1.3 and the absolute open flow potential increased 28% from 110 to 141 MMscf/D.
In a separate study, this sonic tool was also deployed in a stripper oil well to see if sonic stimulation could increase oil production. Two treatments six months apart were performed on a well producing 6.2 barrels per day. For oil well deployment, sonic stimulation could improve well production through both viscosity reduction and through opening up blockages in the pores. Well productivity increased 15-30% in the initial period following treatment and then gradually returned to pre-treatment levels after several weeks.
Reservoir Characterization of the Wabiskaw B in the Kirby Area, Alberta, Canada
Authors: Mathison J. E. , Mireault R. A. , Wilhelm J. K. , Alwast N. K. , Williams S. K. 
Published: December 2007

Summary
An integrated geological and engineering framework of the Kirby Wabiskaw B reservoir has permitted a retrospective analysis of two steam flood pilots that failed to achieve commercial success. The analysis identified four factors that negatively impacted the pilots and which would need to be addressed prior to future steam floods. The factors are: Laterally extensive calcite cemented horizons, interbedded mudstones, pore plugging kaolinite and clay diagenesis upon contact with steam.
Innovative Completion Technology Enhances Production Assurance in Alaskan North Slope Viscous-Oil Developments
Authors: Triolo M. T. , Davis E. R. , Buck B. R. , Freyer R. , Smith L. 
Published: December 2007

Abstract
In the challenging North Slope operating environment, use of innovative production equipment has provided solutions to zonal isolation and packer integrity problems in viscous oil reservoirs. Operators have employed new tools and technology utilizing expandable rubber materials to manage annular fluid flow, control solids/shale production, and achieve zonal isolation in wells where high costs, shallow depths, and long step-outs create unique completion challenges. The new technology is allowing once bypassed zones to be added to existing developments, and making future developments more economically viable.
The new design approach involves installing swelling rubber packer (SRP) technology as part of the completion. This technology is based on specially designed swelling properties of rubber in crude or mineral oil based mud (MOBM) to expand and seal the annulus.
The paper describes one operator's use of as many as 17 devices in a tri-lateral horizontal undulating well to manage annular flow and minimize shale/solids production. The successful application of this technology has allowed shale interbedding to be effectively isolated behind blank pipe, thus allowing an additional zone to be added to the existing development. To date the technology has been applied to eleven wells, improving production assurance.
Another major operator on the North Slope has used the technology to isolate potentially conductive fault crossings along the lateral and inadvertent zonal crossings while kicking off from the parent bore. Multiple packers have been run in single laterals to achieve the desired isolation without noticeable effects on liner running drag. Recent density caliper data shows significantly more washout than previously envisioned, increasing the desire to manage annular flow.
Development and application of this SRP technology is detailed in the paper, including documentation of improved efficiencies as a result of its use. The paper will also discuss field operations, installation, and unique considerations associated with design and installation in viscous oil environments.
Near-Wellbore Damage Remediation in Stripper Wells
Authors: Gitman A. , Watson R. 
Published: December 2007

Abstract
Near-wellbore damage remediation has direct impact on the improvement of the productivity of wells. The objective of this study is to investigate the potential impact of nearwellbore damage remediation on the production of shallow oil wells penetrating the Glade sandstone, located in Warren County, PA. Given the number of shallow reservoirs in the Appalachian and mid-continent basins, understanding of the potential for productivity improvement in the Glade can give insight into the potential for improvement in reservoirs with similar pressure and production rates.
To accomplish this objective, a characterization of the reservoir was first developed using the CMG commercial simulator. History matching of the production data was used in this characterization study. The simulator was then modified using the rock and fluid properties determined during laboratory analysis of the core and fluids obtained from a well penetrating the Glade sandstone. Comparison of the results of these two studies was then used to ascertain the impact of the implementation of near-wellbore damage remediation on improving well performance. In addition an investigation of the reservoir behavior given re-pressurization was performed as an alternative to the near-wellbore damage remediation.
It was concluded that removal of the formation damage would be an inefficient method of enhancing oil recovery for this particular oil field given its low reservoir pressure. By contrast, re-pressurization of the reservoir with CH4 showed positive results on the production from the wells penetrating the Glade sandstone. It was determined that the re-pressurization of the reservoir to a pressure approaching the freshwater gradient with the near-wellbore damage eliminated, would result in the highest increase in cumulative production.
Application of Microseismic Imaging Technology in Appalachian Basin Upper Devonian Stimulation
Authors: Fontaine J. , Willis R. , Griffin L. , Paugh L. , Watson J. 
Published: December 2007

Abstract
Microseismic imaging technology can help in providing the answers to many previously unknown questions involving the process and results of hydraulically fracturing the sandstones in the Upper Devonian wells of the Appalachian Basin. Uncertainties surrounding fracture orientation, fracture length, fracture height, the effect of treatment size, and identification of potential fracture complexities can be reduced. Developing an understanding of fracture geometry is vital and can lead to improvements in reservoir management and development.
Every year thousands of wells are drilled and completed in the Upper Devonian sands throughout the Appalachian Basin. Nearly all of these wells are fracture stimulated in some manner. The tools available to the completion engineer in designing these treatments are limited and uncertainties regarding their efficiency and optimization often exist. Process improvement can be limited or delayed by the lag time involved in determining stimulation effectiveness based upon production results. Even then inferences must be made concerning fracture geometries based upon well testing or fracture modeling. The use of microseismic fracture imaging allows real time or near real time decisions to be made.
This paper will present a case history of the implementation and utilization of microseismic fracture imaging conducted in three multi-stage stimulation treatments in Devonian Sand tight gas wells in Pennsylvania. The created fracture geometries and their implications for future treatment design, fracture model calibration, and reservoir management will be explored.
Ultralightweight Proppants: A Field Study in the Big Sandy Field of Eastern Kentucky
Authors: Kendrick D. E. , Puskar M. P. , Schlotterbeck S. T. 
Published: December 2007

Abstract
Nitrogen foam stimulation treatments using Ultra Light Weight Proppant (ULWP) have been successfully pumped in new gas wells located in the historic Big Sandy Field of Eastern Kentucky. The Devonian Shale play in the Big Sandy Field may be classified as extremely low pressure and low permeability. Straight nitrogen gas stimulation treatments are used in the extreme low pressure areas. Foam fracs, some rather large by Appalachian Basin standards, have been pumped frequently in the higher pressure areas of Pike County.
Ultra light weight proppant is a manufactured proppant consists of a chemically hardened walnut hull core with multiple layers of epoxy resin coating as the outer shell. ULWP has been used on more than 100 wells in the Appalachian Basin. In March of 2004 one large gas well operator decided to experiment with ULWP and replace the standard 2,000 sack – 2,500 sack 20/40 mesh sand foam frac with a similarly sized job using only about one-tenth of the mass of ULWP. Based on well treating pressures, post-frac clean-up and AOF, and short term production data, more jobs were pumped in the same field.
This paper will detail the engineering behind the decision to select ULWP, the foam frac design, and look at post-frac production of both wells using ULWP and its offsets. Finally, the value of using ULWP will be evaluated by considering the production history and costs involved.
Development of a Series of National Coalbed Methane Databases
Authors: Mohaghegh S. D. , Nunsavathu U. N. , Jalal J. , Tovar M. , Maricic N. , Gaskari R. , Ameri S. 
Published: December 2007

ABSTRACT
As the interest in coalbed methane production increases more and more engineers and scientists are becoming interested in the reservoir and sorption characteristics of different coal seams throughout the U.S and the world. As they set out to search for such information it becomes clear that finding such information is not easy. The difficulties associated with collecting such information are due to three major factors. First is the fact that development of CBM reservoirs is a relatively new phenomenon when it is compared with conventional hydrocarbon reservoirs. Secondly, companies that are in possession of such data and information are very protective of their data. They consider them company assets and are not ready to release them. Thirdly, whatever data and information that is available in the public domain is scattered in hundreds of technical papers and publicly funded project reports.
The objective of this paper is to introduce and describe the details of a series of newly developed databases that will soon become publicly available. These databases are a collection of all the publicly available CBM related data and information in one location. This series includes three major databases. First is a literature database that includes the title, authors, topics and summary of all the available technical papers and project reports related to CBM. Each entry includes a summary of the paper and other information that facilitate locating the article or the report. The database includes papers from SPE and CBM conferences and symposiums along with reports published by DOE, GRI and others.
The second database is a collection of reservoir and sorption characteristics of CBM reservoirs that has appeared in the public domain. The data has been organized by basin and field and one can identify ranges and statistics about the available data based on each basin. A reference for each piece of data is also presented. The third database is CBM well productions from different states and different local databases that has been gathered and compiled in one location for easy access. These databases are located and maintained at the Petroleum & Natural Gas Engineering department at West Virginia University.
Reservoir Characterization Using Intelligent Seismic Inversion
Authors: Artun E. , Mohaghegh S. D. , Toro J. , Wilson T. , Sanchez A. 
Published: December 2007

Abstract
Today, the major challenge in reservoir characterization is integrating data coming from different sources in varying scales, in order to obtain an accurate and high-resolution reservoir model. The role of seismic data in this integration is often limited to providing a structural model for the reservoir. Its relatively low resolution usually limits its further use. However, its areal coverage and availability suggest that it has the potential of providing valuable data for more detailed reservoir characterization studies through the process of seismic inversion. In this paper, a novel intelligent seismic inversion methodology is presented to achieve a desirable correlation between relatively low-frequency seismic signals, and the much higher frequency wireline-log data. Vertical seismic profile (VSP) is used as an intermediate step between the well logs and the surface seismic. A synthetic seismic model is developed by using real data and seismic interpretation. In the example presented here, the model represents the Atoka and Morrow formations, and the overlying Pennsylvanian sequence of the Buffalo Valley Field in New Mexico. Generalized regression neural network (GRNN) is used to build two independent correlation models between; 1) Surface seismic and VSP, 2) VSP and well logs. After generating virtual VSP's from the surface seismic, well logs are predicted by using the correlation between VSP and well logs. The values of the density log, which is a surrogate for reservoir porosity, are predicted for each seismic trace through the seismic line with a classification approach having a correlation coefficient of 0.81. The same methodology is then applied to real data taken from the Buffalo Valley Field, to predict interwell gamma ray and neutron porosity logs through the seismic line of interest. The same procedure can be applied to a complete 3D seismic block to obtain 3D distributions of reservoir properties with less uncertainty than the geostatistical estimation methods. The intelligent seismic inversion method should help to increase the success of drilling new wells during field development.
Projections of Marginal Wells and Their Contributions to Oil and Natural Gas Supplies
Authors: Duda J. R. , Covatch G. , Remson D. , Wang S. 
Published: December 2007

Abstract
Low volume wells yield a meaningful percentage of the crude oil and natural gas produced in the U.S. During 2003, about 29 percent of the crude oil and more than 10 percent of the natural gas was attributable to marginal wells. Moreover, more than two-thirds of the wells in the United States are marginal. The value of marginal well production simply cannot be overstated.
Given the significance of marginal production, "first order" forecasts of recent production and well count trends were developed in order to gain insights on the future contributions from these type wells. Volumes of crude oil and natural gas [from marginal wells] are estimated to be approximately 4 Tcfe in 2025, an increase of nearly 20 percent compared to 2003 volumes. Further, the total number of marginal natural gas wells is projected to increase by more than 160,000 to over 400,000 wells. Clearly, myriad policies and technologies must continue to advance in order to keep these wells flowing and contributing to the economic growth and energy security of the United States.
Well-Completion Strategies for Methane Gas Production from Coal Seams Using Simulation
Authors: Bilgesu H. I. , Ali M. W. 
Published: December 2007

Abstract
Natural gas plays an increasingly important role as a clean energy source. It is estimated that 10% of the produced gas comes in the form of methane from coal seams and the contribution of gas from coal is expected to increase to 20% in the next 10 years. There is a need to develop more gas wells that are managed efficiently. The inherent problem is the maximization of production with minimum cost. The maximum production is a function of gas content controlled by the coal properties such as porosity, permeability, pressure, desorption time and ash content. The recent trend is to develop horizontal wells to increase the recovery times by quickly dewatering the seams and to obtain gas production early in the life of the well. Developing horizontal wells in thin coal seams are expensive and the prospects need to be evaluated properly in order to maximize gas production.
Many factors affect the methane production capacity of a coal seam and to find the best well planning and design is a challenge. Many characteristics of coal such as gas content, pressure and saturation are determined. On the other hand, decisions regarding the number, location, and type of wells, completion methods, hole size and similar decisions depend on the properties of coal.
In this paper, we presented the results of a study conducted to investigate the methane gas production strategies for different coal seams. A main goal of this study is to optimize methane gas production from coal seams. Presented in this study are the effects of reservoir properties on the efficiency of selected well design.
Analysis of Non-API Industrial Sands for Use in Hydraulic Fracturing
Authors: Gottschling J. C. 
Published: December 2007

Abstract
Increasing demands on traditional supplies of frac sand have caused shortages of product in some areas. Alternate supplies of frac sand are available. The biggest concern with using these "non API" frac sands is possible negative impact on the well productivity.
The American Petroleum Institute (API) has developed recommended practices for quality control testing of frac sand as well as other types of proppant. Looking at the results of the testing can provide indications about possible damage to the sand pack caused by frac sand of poorer quality than what was used in the past.
The concept of dimensionless conductivity and its relationship to well productivity is helpful in understanding the damage mechanism of resulting from poor quality frac sand. Hydraulic fracture and production simulators can predict the dimensionless conductivity and translate into well productivity.
A Production-Based Method for Direct Estimation of Gas-in-Place and Reserves
Authors: Blasingame T. A. , Rushing J. A. 
Published: December 2007

Abstract
This paper presents a systematic method for the direct estimation of gas-in-place and reserves using only gas production data. The fundamental concept used in this work is "quadratic" rate-cumulative relation, which is given as:
(1) q g = q g i − D i G p + 1 2 D i G G p 2
Where we define the decline constant, Di, for this case as:
(2) D i = 2 q g i [ 1 − [ p w f / z w f p i / z i ] 2 ] G
The basis of our method is the development and application of several rate-time/cumulative production-time plotting functions which are derived using Eq. 1 (see Appendix A). Eq. 1 is itself derived from a rigorous coupling of the gas material balance equation for a volumetric dry gas reservoir and a modified version of the stabilized gas flow equation for a gas well producing at a constant bottomhole pressure. The proposed procedure is designed to simultaneously match the independent plotting functions (developed from Eq. 1), where we note that each function exhibits unique characteristics (e.g., a straight-line trend) which can be used as an extrapolation mechanism for estimating gas reserves.
In this work we utilize a "spreadsheet" approach in which the data and plotting functions are linked by "global" model parameters, thus ensuring consistent evaluations. We verify our methodology using a simulated case and we then illustrate the application of this method using a field case. Although theoretical considerations limit the rigorous use of the proposed methodology to reservoir pressures less than 6,000 psia, we have successfully applied of our method in practice for reservoir pressures as high as 10,000 psia.