bluuebunny/crossref_metadata_2025_split huggingface dataset:
Study of Mechanisms for NORM in Gas Production Facilities in the Antrim Shale of the Michigan Basin
Authors: Ortiz Isaias , Anthony R. V. , Pope D. H. 
Published: December 2007

Abstract
Naturally occurring radioactive materials (NORM), has been observed in conjunction with natural gas production operations in certain Antrim gas wells in northern Michigan. Chemical analyses on field derived water samples from Antrim wells were compared with geologic and engineering Parameters using geologic and completion data in an attempt to determine the source and mechanisms associated with these observations.
The sources of the scale are unknown and potentially hazardous if radioactive levels exceed OSHA Standards. Mitigation measures could be costly and jeopardize the economic viability of the play.
NORM Antrim gas production facilities tested were found to be associated with barium sulfate scale which formed in central separators as well as in individual wells. Low levels of barium were found in waters from most wells, while sulfate was found in only some wells. Two models were developed based on the results of this study. One model assumes that sulfate is migrating from other formations. The other model assumes that the cause of the problems may be due to the mixing of waters and chemical reaction with oxygen, carbon dioxide, and/or bacteria either contained in the Antrim gas or migration from the Antrim outcrop a few miles north of the producing fields. The oxygen and bacteria, contained in the fresh water, may be reacting with pyrite to cause the formation of sulfate. Sulfate in tum is reacting with the naturally occurring barium and radionuclides to form the barium sulfate scale that is being observed in the field. However, from a Chemistry mass balance view, additional oxygen is required than can be supported by fluid migration alone. Other sources of oxygen would have to be introduced.
The Benefits of Applying Technology to Devonian Shale Wells
Authors: Voneiff G. W. , Gatens III J. M. 
Published: December 2007

ABSTRACT
Applying technology to Devonian Shale wells can increase present value profit by $30,000 to $150,000 per well in a typical drilling program by improving stimulation treatment design and results. An intermediate level of technology application is best, costing $6,800 above what a typical operator currently spends. The key objective of the technology application is to optimize the stimulation treatment using a layered reservoir description with accurate formation properties. An accurate layered reservoir description minimizes inappropriate stimulation treatments, consistently resulting in treatments that are close to the optimal treatment.
Natural Gas Markets: What to Expect after Order 636?
Authors: Thompson S. E. 
Published: December 2007

ABSTRACT
Today's Gas Industry has in front of it, its greatest opportunity to recapture its lost market share of the early 1970's. The industry has struggled through many of the restructuring problems, and has a. positive political environment to resolve the remaining problems.
This paper describes the outlook of the future of natural gas markets after the implementation of FERC's Order 636, the final order for natural gas deregulation.
Geometries and Other Parameters of Two Medina Group (Clinton) Gas Storage Fields in Pennsylvania and Ohio
Authors: Pees S. T. 
Published: December 2007

ABSTRACT
The upper "Clinton" sandstones pose gas storage problems. Migration of injected gas may occur over larger areas than expected.
The Medina Group Whirlpool Fm. sandstone (lower "Clinton") occurs as distinct depositional features with vertical and lateral seals. It earlier served for storage in the Pennsylvania Corry field. It deserves attention.
Variations in Temperature Log Response Based on Tool Sensor Location and Logging Sequence
Authors: Walbe K. A. , Rothman E. M. , Stollar Richard , Harris Perry 
Published: December 2007

ABSTRACT
The temperature log has been utilized as an openhole gas entry detection device for over 40 years in wells of the Appalachian Basin.
The air-drilling of the majority of wells in the Appalachian Basin facilitates the use of this log as a qualitative and, in many instances, a quantitative tool in evaluating gas flow from productive intervals.
Historically the temperature log was run in the hole as a down-pass log with an external temperature sensor mounted on the bottom of the tool. However, advances in tool telemetry during the past decade made possible the stacking of logging tools, thus, the external temperature sensor has been moved on many tool strings from the bottom of the tool string to a more central position in the tool stack. This stacked temperature tool data is now recorded during the secondary up-pass portion of a single logging run in order to facilitate the recording of other logs on the primary down-pass.
In order to compare the effects of sensor placement and logging sequence, multiple runs were made in a Columbia Natural Resources well in Roane County, West Virginia, utilizing a single end-mounted temperature tool and a stacked center-mounted temperature tool run during both up and down-passes through productive gas zones.
The resulting temperature log information showed differences in the temperature profiles that were obtained using different tool configurations and different logging sequences.
The information obtained from these runs can be utilized to better understand certain temperature logging anomalies that appear to be inherent in certain tool configurations and logging sequences.
Sour Natural Gas and Liquid Equation of State
Authors: Mohsen-Nia Mohsen , Moddaress Hamid , Mansoori G. A. 
Published: December 2007

ABSTRACT
The major gaseous impurities in the subquality natural gas sources are acidic components, such as hydrogen sulfide and carbon dioxide. Considering that H2S easily dissociates into hydrogen and elemental sulfur, thermodynamic properties and specially phase equilibria of liquid and gaseous systems containing hydrogen, hydrogen sulfide, carbon dioxide, other acidic components, and light hydrocarbons are of much interest to the natural gas and gas condensate production industries.
In this paper we report the development of a simple and accurate cubic equation of state for prediction of thermodynamic properties and phase behavior of sour natural gas and liquid mixtures. This cubic equation of state, which is based on statistical mechanical theoretical grounds, is applied to pure fluids as well as mixtures with quite accurate results. All the thermodynamic property relations of sour gaseous and liquid mixtures are derived and reported in this report. Parameters of this equation of state are derived for different components of sour natural gas systems. The resulting equation of state is tested for phase behavior and other thermodynamic properties of simulated and natural sour gas mixtures. It is shown that the present equation of state, even though it is simple, predicts the properties of interest with ease and accuracy.
Foams and Surfactants for Improved Underground Storage of Natural Gas by Blockage of Water Coning
Authors: Smith D. H. , Jikich S. A. 
Published: December 2007

ABSTRACT
"Foam" blockage to alleviate water coning during the retrieval stage appears to be the simplest, least expensive, and most easily commercialized foam-based technology for improving the underground storage of natural gas. This paper describes effects of injection rate, surfactant concentration, NaCl salinity, and divalent ions on measured aqueous-phase and gaseous-phase relative permeabilities, as well as why these data are needed for modeling the process and designing single-well field tests.
New Solutions for Wells With Finite-Conductivity Fractures Including Wellbore Storage and Fracture-Face Skin
Authors: Liao Yizhu , Lee W. J. 
Published: December 2007

ABSTRACT
This paper presents new solutions for wells with finite-conductivity fractures including wellbore storage and fracture-face skin damage. An infinite-conductivity fracture is included as a limiting case. The new solutions are obtained numerically by modeling a well with an elliptical finite-conductivity fracture in an elliptically composite reservoir. The new solutions are as accurate as published analytical solutions, which are available only for limiting cases. In addition, this study finds and confirms that an "apparent" skin results in a well with a finite-conductivity fracture and fracture-face skin; this "apparent" skin is larger than the true fracture-face skin. The new solutions presented in this paper can be used to analyze production and welltest data for wells with finite-conductivity fractures including wellbore storage and fracture-face skin. Examples are provided.
Prediction of Gas Well Deliverability From Just a Pressure Buildup or Drawdown Test
Authors: Chase R. W. , Alkandari Hassan 
Published: December 2007

ABSTRACT
Predicting the deliverability of a gas well is normally accomplished by conducting a four-point backpressure test, an isochronal test or a modified isochronal test. All of these methods require testing a well at a minimum of four flow rates. Several researchers have worked to advance the theory of predicting gas well deliverability using a one-point test. Their research focused on the development of dimensionless IPR curves for gas wells similar to Vogel's curve for oil wells.
This paper describes a method for predicting the deliverability of a gas well that requires only pressure build-up or draw-down test data. The method utilizes new dimensionless IPR curves that were developed specifically for hydraulically fractured gas wells. The curves may also be applied to unfractured wells by converting the apparent skin factor obtained from a pressure transient test to an equivalent ratio of external drainage radius to fracture half-length (xe/xf) using the apparent wellbore radius concept. Using the new curves or their general equation, an IPR curve can be constructed. In its simplest application, the new method allows an engineer to predict the AOF of a gas well which, when plotted on log-log paper along with the single stabilized point obtained from the pressure build-up or draw-down test, permits the construction of the stabilized deliverability curve and the determination of its equation.
Reservoir Characterization of an Openhole Cavity Completion Using Production and Well Test Data Analysis
Authors: Jochen V. A. , Lee W. J. 
Published: December 2007

ABSTRACT
This paper presents the development of a coalbed methane reservoir description from the analysis of production and pressure transient data for a producing open hole cavity well and two observation wells completed in the Fruitland Formation in the San Juan Basin, Colorado. Data collected and evaluated include open hole drill stem tests and a post-fracture pressure buildup test for the observation wells and multi-well interference tests and pre- and post-cavitation pressure buildup tests and production data for the cavity completed well. The main objective of the work presented in this paper was to gain a better understanding of the mechanisms controlling gas production from open hole cavity completion wells.
The recent emphasis on evaluating the productivity of open hole cavity completion techniques relative to the productivity of cased hole hydraulically fractured completion techniques makes this reservoir characterization important. A good reservoir description may help quantify an increase in the effective permeability, if any, of the coal natural fracture system and help us to understand the reservoir conditions where cavitation may be a suitable stimulation technique for coalbed methane reservoirs. Suitable reservoir conditions may include high permeability, high pressure or a combination of the two. On the basis of the data analyzed, we found that the open hole cavity completion appears to be characterized best with a reservoir description where an altered zone of higher permeability is present around the radius of the cavity to account for the increase in gas production. We will demonstrate that our reservoir description is reasonable by showing a history match of pressure transient and production (gas and water) data both prior to and after the creation of the cavity. We determined the permeability anisotropy of the reservoir natural fracture or cleat system through the analysis of the pre-cavitation interference tests. The geometry and magnitude of the altered zone were determined by matching the postcavitation pressure profiles of the observation wells. We verified the reservoir description by comparing a production forecast based on this description with observed long term data. This study provides a reservoir description that illustrates how a cavity completion can dramatically improve the productivity of a coalbead methane well.
Analysis of Single-Phase and Imbibition Experiments for Slot and Solution Pores Type of Tight Sand at Various Overburden Pressures
Authors: Arastoopour Hamid , Pakdel Parto 
Published: December 2007

Abstract
Imbibition runs at different overburden pressures have been performed on a SFE2-8707 sample from the Travis Peak formation (slot and solution pore type), with an approximate porosity of 7% and gas permeability of 22 to 37 μd, using our physical model. The experiment continued for several days untill the water flow rate reached the steady state values. The single phase water flow experiments were performed at several inlet and overburden pressures, following the imbibition runs.
The results from imbibition and single phase water flow experiments showed that under different overburden pressures, due to the porous structure changes, considerable amounts of pore closing and opening occurred which resulted in an overall increase in permeability of the sample. However from single phase gas flow experiments an overall decrease in permeability of the sample was observed. Furthermore the single phase transient experiments compared well with steady state runs. This proves the reliability of transient runs which results in significant saving in time and expense for core analysis of tight core samples.
Estimating Permeability Profiles Using Core and Log Data
Authors: Yao C. Y. , Holditch S. A. 
Published: December 2007

ABSTRACT
This paper presents a method to correlate core permeability with open-hole well log data. The model correlates porosity, deep resistivity, shallow resistivity and gamma ray index to permeability and eliminates the need to know values of irreducible water saturation or grain diameter as required in previously published correlations. We provide data from three Gas Research Institute research wells to illustrate the correlation.
A Method for Designing and Predicting the Sucker Rod String in Deviated Pumping Wells
Authors: Xu Jun , Hu Yuren 
Published: December 2007

ABSTRACT
Commonly used methods at present for designing rod pumping unit presume vertical wells and are often applied to the design of deviated wells in field practice. This may be possible to cause substantial errors in the analysis of deviated wells because performance and load-deflection pattern of the rod in deviated wells are different from those in vertical wells. Due to bolehole geometry, curved turbing makes the rod result in transverse displacements which is coupled by longitudinal displacements. In this case, load-deflection calculations become more complicated, and, in general, six components of stress resultant or internal forces may appear at any cross section along the rod. Besides, Coulomb friction between the rod and tubing and contact of the rod with tubing are also serious and difficult problems.
Kinetic Approach to the Oil Recovery Simulation for Heterogeneous Reservoirs
Authors: Izmailov A. F. , Myerson A. S. , Kessel A. R. 
Published: December 2007

ABSTRACT
A new system of kinetic equations is suggested to describe pressure distribution in the reservoir porous medium in the course of oil recovery. The equation system accounts the reservoir characteristics and boundary conditions together with the distribution of injection and production wells. The system solution provides the time-dependent evolution of the reservoir pressure in every site of the reservoir modelling lattice. The Dynamic Percolation Invasion with Trapping model [6,7] is adjusted for the heterogeneous case when the reservoir local characteristics are time- and recovery technology-dependent. The special software is created to simulate and visualize the oil recovery process in 3D. Simulation results are verified in numerous laboratory experiments with sand tanks and in a test field.
Well Log Interpretation of a Devonian Gas Shale: An Example Analysis
Authors: Guidry F. K. , Walsh J. W. 
Published: December 2007

ABSTRACT
Because of the complex mineralogy, calculating accurate values of lithology, porosity and saturation in the Devonian Gas Shale cannot be done with traditional well log interpretation models. Tool response and relative volumes for each of the mineral components must be determined first to then accurately calculate porosity. A technique to analyze well logs in Devonian Shale has been developed by ResTech under a contract with Gas Research Institute. This paper demonstrates the steps and procedures used in this log interpretation methodology. A Devonian Gas Shale from the GRI Comprehensive Study Well Program (CSW No. 1A) is used to illustrate the analysis technique. For further information on the development of the model, refer to "Devonian Shale Formation Evaluation Model Based on Logs, New Core Analysis Methods, and Production Tests", Guidry, Luffel, Olszewski, and Scheper, Transactions SPWLA, 1990.
Dynamic Modeling of Permeability and Small-Scale Stratigraphy in a Core Plug
Authors: Trygstad J. C. 
Published: December 2007

ABSTRACT
System dynamics modeling of flow and rock textures might be helpful for testing hypotheses on changing flow capability of reservoir rock. It is desireable to be able to model changing rock textures and flow capability in the computer because most reservoir rock volume is located away from cored wells and is not accessible for direct observation and measurement.
To use system dynamics modeling, a system must change over time. We know flow pathways change over time, because of diagenetic processes, and because of formation damage and production itself. System dynamics models are constructed by modeling assumptions about present conditions. System behavior, for example flow, is then simulated by changing certain specific conditions. When simulation results do not match our hypotheses, then either our hypotheses are wrong or our basic assumptions of the model are wrong. If simulation results mirror our expectations, then we have an effective model for communicating our assumptions and predictions to others. Thus dynamic modeling tests our ideas and hypotheses, and it communicates these to others. Because modeling is used in most disciplines, organizing geologic information in system dynamics format eases communication of geologic information across disciplines, presenting it explicitly.
A dynamic model that demonstrates interactions among small-scale stratigraphy and flow parameters in a core plug is presented here. It was developed using commercially available STELLA software. In the core plug and in the model, diagenetic processes have modified depositional textures. Data categories are organized into feedback loops according to suggested relative influences on each other. These influences are described by equations or "if-then" statements.
Estimating Recovery Efficiency and Permeability From Mercury Capillary Pressure Measurements for Sandstones
Authors: Owolabi O. O. , Watson R. W. 
Published: December 2007

ABSTRACT
Adequate estimation of the field behavior during primary and enhanced recovery period requires representative laboratory measurements. Moreover, the estimation of the behavior from mercury capillary pressure data is important when routine measurements cannot be performed, as in the case of very small core plugs or drill-cuttings. The estimation is also important when there is need to minimize core analysis cost or when the measurements of the behavior are of questionable accuracy, as in the case of reservoir rocks with microfractures.
The objective of this study is to develop new empirical recovery efficiency and permeability correlations to improve the accuracy of estimating behavior of fluid flow through various layers of sandstone reservoir rocks. The correlations were developed from 450 experimentally obtained mercury capillary pressure measurements, using non-linear multiple regression analyses approach.
The correlations are simple to use and can be used in a reservoir simulator with appropriate rock and fluid property data to predict field production performance. The predictive strength of the new empirically derived correlations for sandstones were found to be superior to the existing correlations for estimating recovery efficiency and permeability.
Formation Evaluation Using Core, Well Log, and Initial Production Data
Authors: Bilgesu H. I. , Ameri Samuel , Aminian Khashayar 
Published: December 2007

ABSTRACT
Accurate description of the porosity and permeability distributions are the key for reservoir performance predictions. The porosity of the formation can be evaluated from the cores and/or well logs while the permeability is usually determined from the cores and/or well tests. Usually cores and well test data is often abundant Therefore, the evaluation of permeability and porosity distributions from well log data in heterogenous formation represents a significant technical as well as economic advantage. However, the evaluation of permeability from well log data represents a difficult and complex problem in heterogenous formation.
The goal of this study has been to develop a methodology for determining porosity and permeability distributions in a heterogeneous formation utilizing geophysical well logs. Granny Creek Field in West Virginia has been selected as the study area in this paper. This field has produced oil from Big Injun Formation since early 1900's. The water-flooding operation was initiated in 1970's and currently is in progress. Well log data are available on substantial number of wells. Core samples are also available from a few wells.
Core samples and the well logs were analyzed to determine permeability, porosity, and water saturation. In addition, the results of core analysis and well log interpretations were complemented by geological information and initial production data to develop a correlation between permeability, porosity, water saturation, depositional environment, and pore type. The results were employed for development of porosity and permeability distributions. The methodology presented in this paper could serve as a guideline for correcting permeability with other rock parameters in heterogenous formations. The complexity of such correlations is directly proportional to degree of heterogeneity of the formation.
Hydraulic Fracturing Design Optimization
Authors: Hareland Geir , Rampersad Paul , Dharaphop Jirapong , Sasnanand Sunthan 
Published: December 2007

Summary
This paper uses a three-dimensional three stress layer hydraulic fracturing model in conjunction with a fractured reservoir production model to optimize hydraulic fracture design. The hydraulic fracturing model has varying widths along the fracture and has the option to choose constant, linear or parabolic fracture height growth criterion. The fracturing fluid rheology is modeled with a non-Newtonian pressure loss model in the fracture, with the special case being the Newtonian model. The fractured reservoir production model uses an equation formulated from a work by Guo and Evans1,2. In this paper the specific reservoir properties were taken from a tight gas sandstone section of the Mesa Verde formation in Colorado3. It should be noted that the fracturing and production of any oil or gas reservoir can be simulated with this procedure. The fracturing parameters optimized in this paper are fracture length and fracturing fluid pump rate. The economics show that this optimization approach has great promise and that it can predict net revenue.