bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Methane Content of San Juan Basin Coal: Implications for Coalbed Methane Resource Assessments
Authors: Smith Douglas M. , Williams Frank L. , Sato Tet , Lee Young H. , Malone Rodney D. 
Published: December 2007

ABSTRACT
The potential methane resource for the Fruitland coal formation of the San Juan Basin of northwest New Mexico has been analyzed. Gas contents ranging from 1 to 8 cm3/g were found for 33 samples from 14 wells which were at depths from 300 to 1000 m. Gas contents were determined using the "chip desorption" method. This method allows the use of drill cuttings obtained from conventional drilling operations as the coal seam is penetrated. The use of core samples which is required in the Bureau of Mines method is eliminated.
Contrary to past basin studies which used a limited number of data points, no direct correlation between depth and in-place gas content was evident. In order to explain the lack of a depth/gas content relationship, the physical properties of the coal relevant to gas adsorption were studied. Surface area measurements using low-pressure CO2, CH4, and neopentane adsorption have been conducted. Differences in adsorption capacity between the various samples is small and cannot explain the order of magnitude variation in gas content. In summary, it appears that local geological factors (i.e., the nature of the over and underburden) play a much larger role in the in-place gas content of coal than previously thought. This implies that a large number of data points is required to accurately characterize the total quantity of coalbed methane in a particular basin.
Evaluation of Different Models for Injectivity Decline Prediction
Authors: Furtado C. J. A. , Souza A. L. S. , Araujo C. H. V. 
Published: December 2007

Abstract
There are several kinds of injectivity decline models, going from phenomenologicals ones, that consider the suspended solid mass balance and its damage on well and reservoir, through empirical models based on the experience with a previous field or even historical data. This article presents an evaluation of three differents models: –Phenomenological model: considering mass balance, internal and external (cake) damage and mobility effects when water is injected above the oil-water contact;–Cake properties prediction coupled with flow simulator and;–Empirical model based on previous Perkins and Gonzalez work.
In this work, we compare results from these models and adjust them to fit historical data from injectors wells. Using literature date, we have also estimate parameters from all models and use them to predict the same well behaviour.
Tight Sands: Rapid Mapping From a Computerized Data Base of Well Completions
Authors: Hohn Michael Ed. , Behling Mary C. , Avary Katharine Lee , Patchen Douglas G. 
Published: December 2007

ABSTRACT
Criteria for designating tight formations according to Federal Energy Regulatory Commission Order 99 include limits on maximum permeability and rates of natural production versus depth. Requests for such tight formation designation are to be accompanied by locations of all wells producing from that formation or by a listing of all producing wells.
The role of the West Virginia Geological and Economic Survey in this State's recent successful submittal to the Federal Energy Regulatory Commission was that of providing the necessary computer-generated maps and listings of well documentation for the proposal for Fayette and Raleigh Counties. Similar work for most of West Virginia is in progress. Using a computerized database containing information from drillers' logs, penetration and production maps were plotted showing well locations, permit numbers, and well type (gas, oil, combination, or dry/miscellaneous) for specific pay sands. Precision of the maps depends ultimately upon the quality of the data submitted on the drillers' logs.
Current to within the past 3 to 6 months, the computerized database can be accessed through request-specific utility programs which prepare working files for the SURFACE II mapping package. The maps thus produced expedited definition of both scattered and concentrated areas of production and areas of dry penetrations; associated listings supplied the necessary well documentation including natural open flow rates. Rapid delivery of these maps and reports illustrates the value of maintaining detailed, computerized files on well completions. (Permission to publish is granted by the Director and State Geologist, West Virginia Geological and Economic Survey.)
New Downhole Fluid Analysis (DFA) Technologies Supporting Improved Reservoir Management
Authors: Cañas Jesús A. , Freitas Evie , Andrews A. Ballard , Mullins Oliver C. , Colacelli Santiago E. 
Published: December 2007

Abstract
This paper describes a new Downhole Fluid Analysis technology (DFA) being implemented in Latin America for improved reservoir management. DFA is a unique process in fluid characterization for improving fluid sampling, reservoir compartmentalization evaluation and support flow assurance analysis. It combines known and new fluid identification sensors, which allow real time monitoring of a wide range of parameters as GOR, fluorescence, apparent density, fluid composition (CH4, C2, C3-C5, C6+, CO2), free gas and liquid phases detection, saturation pressure, as well WBM & OBM filtrate differentiation and pH, which is key for real time contamination monitoring at the well site with the objective of representative sampling and reservoir compartmentalization analysis. This process is not limited to light fluid evaluation or sandstones.
The combination of DFA Fluid Mapping with pressure measurements has shown to be very effective for compartmentalization characterization. The ability of thin barriers to hold off large depletion pressures has been established, as the gradual variation of hydrocarbon quality in biodegraded oils. In addition, heavy oils can show large compositional variation due to variations in source rock charging but without fluid mixing [1].
Using this method we present field DFA data acquisitions and integrate into numerical simulation modeling to conceptually evaluate the impact of fluid composition / properties gradation and compartmentalization in the productivity of some Latin America reservoirs.
NMR Logging Tool Development: Laboratory Studies of Tight Gas Sands and Artificial Porous Material
Authors: Brown Joseph A. , Brown Lee F. , Jackson Jasper A. , Milewski John V. , Travis Bryan J. 
Published: December 2007

ABSTRACT
We report proton. longitudinal relaxation (T1) measurements on water-saturated samples of Western Tight Sas Sand Core and artifioal porous materials. The artificial samples, with well-characterized and nearly uniform pore structure, serve as a calibration standard for preliminary-efforts at inverting the Nuclear Magnetic Resonance relaxation data on the Gas Sand core samples to obtain a distribution of pore surface-to-volume ratios. The distributions obtained show good to excellent agreement with those obtained by mercury porosimetry on the same samples. Various possible effects are discussed, which could account for the discrepancies observed.
The Effects of Mining and Methane Production Activities on Dynamic Reservoir Conditions
Authors: Boyer Charles M. , Dobscha Francis X. , Schwerer Fred C. , Stubbs Paul B. 
Published: December 2007

ABSTRACT
Six unstimulated vertical wells were drilled into the Blue Creek coalbed to measure the changes that occur in coalbed reservoir characteristics because of mining activity. Results indicate that an advancing mine face affects only a small area of the coalbed ahead of the face. If the mine face remains stationary, the coalbed area affected by the face increases with time.
Multiple Zone Coal Degasification Potential in the Warrior Coal Field of Alabama
Authors: Graves Stanley L. , Patton Abner F. , Beavers Wendell M. 
Published: December 2007

ABSTRACT
The upper Pottsville Formation in the Warrior Coal Field of Alabama has seven recognized groups of bituminous coal seams. Three of these groups, the Pratt, Mary Lee, and Black Creek consist of seams containing commercially significant quantities of methane. Each group has several seams within a vertical interval that, in many areas, can be collectively stimulated. In parts of the Warrior Coal Field, where all three groups can be penetrated in one vertical borehole, the potential production from multiple zone completion wells can result in commercially profitable wells. Various open hole and through the casing completion procedures are being applied resulting in successful methane production from these multiple zone coal gas wells.
Production and Utilization of Coalbed Methane Gas in Island Creek Coal Company Mines
Authors: Von Schonfeldt Hilmer , Pothini B. Rao , Aul George N. , Henderson Roger L. 
Published: December 2007

ABSTRACT
Occidental Research Corporation has for the past five years been actively engaged in a research program of draining methane gas from the Pocahontas #3 coal seam. This work is being conducted in Island Creek Coal Company's deep mines in the Virginia Pocahontas Division. The technique consists of drilling long horizontal inseam holes in advance of mining. The initial objective of the program was to reduce methane emissions in mine workings in order to improve mine safety and productivity. As the research program evolved, potential for commercial scale production and utilization of the gas resource became apparent. Current research activities include production and capturing of the gas and utilization at the mine plant for drying the coal. To date 27 horizontal holes have been drilled in three mines for an aggregate depth of over 6,400 meters (21,000 feet). The longest hole is 835 meters (2,740 feet). Over 18.4 million cubic meters (650 MMCF) of pipeline quality gas has been drained and transported safely to the surface through a network of underground pipelines. Coal dryers have been retrofitted with gas burners to replace #2 fuel oil and pulverized coal for drying coal.
A Step by Step Approach to Hydraulic Fracture Treatment Design, Implementation, and Analysis for Tight Gas Sands
Authors: Ahmed Usman , Schatz John F. , Abou-Sayed Ahmed S. , Jones Arfon H. 
Published: December 2007

ABSTRACT
A synthesis of treatment design parameters, treatment procedures in the field, quality control, and analysis of created fracture parameters is essential to improve and optimize hydraulic fracture treatments in a particular field. This paper provides a step-by-step approach to treatment design optimization that combines laboratory, field and analytical efforts. The laboratory program includes measurements of porosity, absolute and relative permeability, capillary pressure, elastic moduli, matrix permeability and proppant bed sensitivity to fluid (reservoir and treatment) all at simulated in-situ conditions and appropriate petrographic study. The field test program involves in-situ stress measurements (mini-fracs in the pay and surrounding formations), fracture orientation determination and transient pressure tests. Successful implementation of the optimized design is then carried out by monitoring of flow rate and bottom hole pressure during the job and change of design parameters as necessary to tailor the fracture geometry. This must be coordinated with a quality control program for both the equipment and materials used in the job. A brief review of the state-of-the-art of transient pressure analyses of fractured wells is also included in the paper to inform the practicing engineer of the advantages, disadvantages and limitations of each technique. Finally, a field example is presented that illustrates the step-by-step approach. Designed and created fracture parameters are critically compared to demonstrate the effectiveness of the procedure and show how such information can be used to further improve results.
We gratefully acknowledge the Gas Research Institute (GRI) and the U.S. Department of Energy, which have funded some of the work presented here.
The Occurrence and Magnitude of Methane — Hydrate Accumulations
Authors: Zielinski Ronald E. , Mclver Richard D. 
Published: December 2007

ABSTRACT
Solid, ice-like mixtures of natural gas and water have been found immobilized in rocks beneath the permafrost in Arctic basins, and in muds under deep water along the continental margins of the Americas. While these unusual compounds have been known and studied by chemists for over a century and a half, and by gas transmission engineers for the past fifty years, the discovery of natural occurrences came as a surprise to earth scientists.
Hydrates of methane gas are stable at temperatures above the freezing point of water if the pressures exceed about 400 psi (2.8 MPa). Therefore, natural gas at near-saturation volumes would combine with water to form a solid in areas of low temperature and moderate-to-high pressures, eg., in sediments immediately beneath thick permafrost, or immediately beneath deep (ca 300 m) water. The structure of hydrates -- a crystalline network of interconnected water molecules, the interstices of which contain single molecules of gas -- is such that there are almost six water molecules for each gas molecule combined into the crystal.
Hydrates are solid; therefore they have the potential of immobilizing large quantities of both water and gas in favorable environments. These solid masses will act as barriers to normal fluid movement through the host sediments, and may even form seals and traps that will trap free gas where the structure and stratigraphy of the rocks themselves would not. Moreover, at about 300 meters, a unit volume of reservoir under permafrost can contain six times as much gas in the hydrate form as in the free gas form. This enrichment factor decreases with depth, reaching parity at about 2000 meters, but is an important consideration in calculating possible gas reserves in Arctic regions.
Because such large areas of sedimentary basins of the globe are underlain by permafrost or are covered by water (along the continental margins), the volumes of gas locked in hydrate "reservoirs" may be enormous. For example, based on Soviet estimates of hydrated reserves in Siberia, the shallow reservoirs under the permafrost of North America would contain 200 trillion cubic feet (TCF), or 5.7 × 1012m3, of such gas. The muds under the deep water along the continental margins of North America could contain almost 20,000 TCF, or 5.7 × 1014m3, of gas, but probably only a small fraction, eg., 200 TCF (5.7 × 1012mi, in rocks porous enough to be considered reservoir rocks.
None of this gas is recoverable with present technology. However, the very magnitude of the resource is so large that naturally occurring hydrates should be the object of continuing study and research.
Detection and Evaluation Methods for In-Situ Gas Hydrates
Authors: Goodman M. A. , Giussani Alberto P. , Alger Robert P. 
Published: December 2007

ABSTRACT
Gas hydrates can occur naturally in subsurface formations under equilibrium pressure conditions. These conditions exist in most arctic and deep offshore regions.1–5
During exploratory drilling for oil and gas in the arctic, operators have encountered insitu hydrates that pose engineering problems. Although these zones are often non-productive, they must be evaluated for well control purposes and well completion design.6–7 The potential of hydrates as an energy resource has also received much attention over the past ten years. Studies of production methods have been undertaken and hydrate coring procedures have been investigated.8–10
With the increased interest in naturally occuring hydrates, the need for improved detection and evaluation methods has also increased. In this paper, logging of hydrates is discussed and selected logs from four arctic wells are examined. A new procedure based on temperature log analysis is described. The concept of a downhole heater for use with drill stem testing is also described for testing and evaluation of hydrate intervals.
Flow Characteristics of Geopressured Reservoirs
Authors: Amirijafari Bahram , Sharer John C. , Rigby Fred Alan 
Published: December 2007

ABSTRACT
A simple mathematical model was developed to simulate production out of a geopressured reservoir about 15,000 ft. deep and injecting the water into a shallow zone of about 6,000 ft. The model represents a two phase (gas/water) flow in a radially symmetric system. Pressure drawdown curves vs. time for a 30-year period are obtained for a constant drawdown rate or a constant well bore pressure.
A sensitivity analysis was performed on some key parameters to determine the impact of gas accumulation in the formation on production. The impacts of various completion choices on the productivity of the well are also discussed.
A successful program for gas production linked to withdrawal of large volumes of water from a geopressured reservoir will require that the well be designed to keep pressure losses in and near the wellbore within acceptable ranges. Effects of tubing size, perforation program, and gravel packing are discussed.
Evaluation of Devonian Shale Reservoir Using Multi-Well Pressure Transient Testing Data
Authors: Lee Byung Oh , Alam Javaid , Sawyer Walter K. , Horan Keith , Frohne Karl-Heinz 
Published: December 2007

ABSTRACT
A multi-well test program designed to study the gas production mechanisms of the eastern Devonian shale reservoirs was completed. Two offset wells were drilled as observation wells in Meigs County, OH. This paper presents the engineering design of the tests, data acquired, analysis techniques, and results of the analysis.
The results indicated a complete anisotropic, layered reservoir system which implies directional gas flow and orientation of natural fractures. This study has provided an insight into the production behavior of reservoirs. It will aid future development of shale gas by optimizing well spacing and understanding of the gas release mechanisms of the Devonian shales.
A Practical Model for Evaluating a Well Producing From a Tight Gas Formation
Authors: Crafton James W. , Poundstone David J. , Brown Charles A. 
Published: December 2007

ABSTRACT
A composite model for gas well performance evaluation and prediction has proven successful and efficient in analyzing gas wells producing from low permeability tight gas formations. By employing analytic methods which model reservoir and fracture behavior, a model has been constructed which is capable of automatic regression for the descriptive reservoir parameters. The model is designed to treat producing and shut-in conditions ranging from a simple four-point test to several years of online pressure-production history. Once history-matched parameters are determined, the model is then capable of projecting future performance.
Field examples of wells producing from tight reservoirs (Eagle; Medina; Niobrara) are presented to demonstrate the applicability of the model in both production performance analysis as well as long term forecasting. These results are compared to finite difference simulation results to demonstrate the model's consistency. In addition, the computational needs of the model in terms of processing time are compared to those of a finite difference simulator.
Evaluation of Below Bubble Point Viscosity Correlations & Construction of a New Neural Network Model
Authors: Ayoub M. A , Raja D. M , Al-Marhoun M. A 
Published: December 2007

Abstract
This paper, precisely, evaluates two famous below bubble point viscosity correlations and tries to create a new Neural Network model for estimating this property. The new created model outperforms the two investigated correlations namely Khan Model (1987) and Labedi Model (1992). The new technique (Artificial neural network) found to be successful in developing a model for predicting viscosity below bubble point with an outstanding correlation coefficient of 99.3%. A limited number of data points have been collected from Pakistani fields in order to construct, test, and validate the model. Viscosity from 99 sets of differential liberation data covering a wide range of pressure, temperature, and oil density were used to validate the correlations and to develop the new model. A series of statistical and graphical analysis were conducted also to show the superiority of the model that has been formulated through an Artificial Neural Network technique. A thorough literature review is also made to check the applicability of the existing correlations and their drawbacks.
Fracture and Permeability Enhancement With Pulse Tailoring
Authors: McHugh Stuart Lawrence , Keough Douglas 
Published: December 2007

ABSTRACT
As part of a DOE program, SRI International performed 1) laboratory experiments to determine borehole-loading-dependent fracture phenomenology and to measure material and fracture properties and 2) computational simulations of fracturing in laboratory experiments and field tests. The fracture data obtained from the laboratory experiments was successfully used to computationally predict the ordering of fracture and permeability enhancement in field tests.
Study on Productivity Evaluation and Performance Prediction Method of Over-pressured, Stress-Sensitive Gas Reservoirs
Authors: Hedong Sun 
Published: December 2007

Abstract
Forecasting the productivity and performance of overpressured, stress-sensitive gas reservoirs is a major challenge for reservoir engineering.
An evaluation method of the effect of stress sensitivity on gas deliverability is presented. This paper introduces a new pressure function, which results from a normalization of the pseudo-pressure and has the dimension of a pressure. Stresssensitive permeability property is taken into account using the permeability modulus. For a practical overpressured, stresssensitive gas reservoir, the gas deliverability is calculated and evaluated. The results show that the decrease degree of gas deliverability is different and it depends on the permeability modulus in the formation on which the gas well is located.
And by combining the binomial equation of gas wells with material balance equation, the basic performance prediction model is established. The tank material balance equation for gas reservoirs has been written taking into account the effective compressibility of formation. The optimum is to determine the compressibility in the laboratory using cores from the reservoir under study. An example is given to show the effectiveness of the new method. The calculation results show that the methods presented in this paper are reliable and correct. The model can preferably predict the production performance in the stable production period and the production decline period of overpressure gas reservoir.
An Experimental Study of Interaction Between Hydraulically Induced and Pre-Existing Fractures
Authors: Blanton Thomas L. 
Published: December 2007

ABSTRACT
Hydraulic fracturing experiments have been performed in the laboratory in pre-fractured material under triaxial states of stress. Tests have been run on naturally fractured blocks of Devonian shale as well as blocks of hydrostone in which the angle of approach of the hydraulic fracture to the pre-fracture was varied in a systematic way. It was found that hydraulic fractures tend to cross pre-existing fractures only under high differential stresses and high angles of approach. In most cases the hydraulic fractures were either diverted or arrested by the pre-existing fractures.