bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Component Performance Evaluation of Constructed Surface Flow and Wetlands Cells for Produced Water Treatment in the Pitchfork Field, Wyoming
Authors: Caswell P. C. , Gelb Dan , Marinello S. A. , Emerick J. C. , Cohen R. R. 
Published: December 2007

ABSTRACT
The quality of produced water discharge is of increasing concern as the quality of potable waters in western states becomes a critical issue. The impact of discharged waters on the downstream water quality, as well as the flora and fauna within the discharge zone, is dependent on the quality of the water ultimately released into the drainage basin from the field. West of the 98th meridian, where surface discharge of produced water is permitted through the NPDES program, many permits are being re-evaluated and in some cased recalled due to actual and/or perceived impacts on the surface and ground water. In Wyoming, the quality of the water is of even further concern because of its potential use by farmers and ranchers.
This paper evaluates a water treatment system that consists of four surface flow cells and a wetland unit. To develop effective design criteria and to isolate the various treatment mechanisms, the system components were independently analyzed.
The system has been operational since May of 1991 with periodic sampling and testing. Initial results are very encouraging. The system appeared to handle the winter stress by a shift in active processes and locations. Mechanical, chemical, and biological treatment in the surface flow cells and wetlands unit have significantly reduced the existing sulfide problem, as well as having reduced the released radium concentration.
MRI Studies of Permeability Control Using Biopolymers
Authors: Barrufet M. A. , Perez J. M. , Mondava S. S. , Ali Liagat , Poston S. W. 
Published: December 2007

ABSTRACT
Severe changes in rock permeability among adjacent oil bearing horizons presents an enhanced oil recovery problem. Fluids used to displace indigenous oil tend to follow the high permeability avenues, bypassing large reserves of oil.
The use of a modified biopolymer, starch, as a method to enhance oil recovery was evaluated by analyzing: 1) changes in rock permeability caused by the macromolecular gel matrix of the polymer solution, 2) mobility reduction due to the higher viscosity of the polymer solution compared to that of water, 3) the chemical and mechanical stability of the biopolymer at reservoir conditions, 4) the effect of various polymer injection strategies, and 5) sweep efficiencies by Nuclear Magnetic Resonance Imaging (NMR/MRI).
Artificially as well naturally consolidated porous media with initial permeabilities ranging from 1,500 to 2,500 md were used. The average permeability reduction was from 1,500 to 500 md when a 1% by weight biopolymer was used. NMR/MRI proved to be a very useful tool to evaluate the effectiveness of a starch biopolymer for rock permeability control. Vertical sweep efficiencies measured by NMR means improved from 25% to 95% with the introduction of the biopolymer. Oil recovery was dramatically enhanced from 2% of the Original Oil in Place (OOIP) using brine as driving fluid to 98% when the in-house biopolymer was used during the displacement tests. Differential pressure (Δp) across 3-inch long samples constantly increased from 10 to 130 psi. A xanthan-gum based commercial biopolymer yielded a recovery of only 58% of the OOIP when used under similar conditions. Displacement experiments were conducted at 1,000 psi and 160°F. The polymer solution exhibited moderate shear thinning viscoelastic behavior and pronounced shear thickening viscosity with increasing brine and polymer concentration.
Flow Of A Disperse Emulsion Of Crude Oil In Water In Porous Media
Authors: Cartmill John C. , Dickey Parke A. 
Published: December 2007

Abstract
It has been suggested that oil migrates through reservoir sands in the form of a fine, disperse emulsion of oil in water, and that oil accumulations occur where the stream enters finer-grained rock such as silt or shale. In order to investigate the possible mechanisms, stable emulsions of oil in water were prepared without the use of wetting agents. They consisted of droplets 1/2 to 1-1/2 microns in diameter, in a concentration of 20 to 40 parts of oil per million of water. These emulsions passed freely through filter paper and ordinary passed freely through filter paper and ordinary sand. A plastic tube containing glass beads of 200-microns diameter included a bed 1/2-cm thick of crushed beads 37 to 88 microns in diameter. When the emulsion was passed through this tube, up to 80 percent of the oil was screened out at the coarse-fine interface. The amount removed depended on the contrast in grain size, the nature and the preferential wettability of the media. Similar results occurred when quartz sand was used as the coarse, and crushed sand as the fine medium. This screening did not occur as a result of capillary effects., because the pores were many times the diameter of the droplets. The oil collected as a result of flocculation of the droplets into strings and clusters., and the oil saturation in the pores consisted of masses of droplets with very little coalescence. Possibly electrostatic forces are more important Possibly electrostatic forces are more important than capillary in the behavior of fine, disperse, oil-in-water emulsions. our current ideas on multiphase flow in porous media may not apply to disperse emulsions.
Introduction
The physical mechanisms of the migration of oil, including the expulsion of oil from the source rock, its migration, and its accumulation in the reservoir rock, are very poorly understood. Most authorities believe that the expulsion of water from compacting shale causes regional flows of water within the pores of the enclosing sediments, and the water somehow carries the oil with it. Hydrocarbons heavier than decane have such a low solubility in water that it is inconceivable that large quantities could have migrated as true solutions. Most subsurface waters have near normal oil-water interfacial tension, so that migration in "solubilized" form as suggested by Baker is improbable. Conventional reservoir mechanics require that oil occupy more than 15 percent of the pore volume in order to exist as a continuous, mobile component. No doubt migration in the continuous phase has occurred frequently, especially secondarily when previously formed oil accumulations have been shifted by tilting of the reservoir rocks. However, such movements should leave residual oil saturations and staining in the flow paths.
Characterization of Pore Structures Using NMR-Restricted Diffusion Measurements
Authors: Chen Songhua , Miao Peizhi , Watson A. T. 
Published: December 2007

Abstract
The self-diffusional motion of fluid molecules in a porous medium is expected to be different from that in the bulk fluid due to the presence of pore boundaries which restrict the molecules diffusing within the pore space. Thus it is conceivable that the study of restricted diffusion may provide information leading to pore structure characterization. We report the use of pulsed field gradient nuclear magnetic resonance (PFG NMR) techniques to study proton restricted self-diffusion in porous media. Measurements were conducted in model porous media consisting of different sized glass bead packs, as well as porous rocks. Computational analyses were carried out to obtain apparent diffusivities and other characteristics from the experimental results.
Dynamic Capillary Pressure Curve for Water/Oil Displacement in Porous Media: Theory vs. Experiment
Authors: Kalaydjian F. J- M. 
Published: December 2007

Abstract
The dependence of the capillary pressure on the flow rate, for two-phase flow in porous media, has been theoretically and experimentally investigated.
A theoretical dynamic expression for the capillary pressure has been derived which involves a dynamic term which is proportional to the time derivative of the saturation. A series of waterfloods have been performed at different flow rates. While flowing the cores, capillary pressure and saturations have been locally measured. Capillary pressure has been found to depend on the flow rate as theoretically predicted: it increases with the flow rate and its derivative with respect to saturation mostly decreases when the flow rate is increased.
The dynamic term is interpreted as the contribution of the viscous forces to the pressure drops. A strong impact of this dynamic expression on two-phase flow modelling and calculation of relative permeabilities has been found.
Laboratory Testing of a Microbial Enhanced Oil Recovery Process Under Anaerobic Conditions
Authors: Rouse Bruce , Hiebert Franz , Lake L. W. 
Published: December 2007

Abstract
Microbial enhanced oil recovery (MEOR) is a potentially attractive way to recover additional or incremental oil from a reservoir beyond conventional operations. The objective of this work was to determine the effectiveness of a commercial MEOR iystem in controlled laboratory corefloods. The experiments were carried out as support for a field test conducted in the Shannon Formation of the Teapot Dome reservoir.
Two sets of coreflood experiments were designed in order to carry out this research. The first set was designed to determine the incremental oil production of each of the components of the MEOR system, both individually and in all possible combinations. The second set of experiments attempted to maximize the opportunity for incremental oil production to occur. The results indicate that, under the conditions tested, there was no incremental increase in oil recovery as a result of the MEOR system.
Mixed Culture Microbial Enhanced Waterflood: Tertiary MEOR Case Study
Authors: Portwood J. T. , Hiebert F. K. 
Published: December 2007

Abstract
Microbial enhanced oil recovery (MEOR) is rapidly developing as a technology, and case studies from field applications are essential to its growth. This paper will discuss a small waterflooded reservoir which was inoculated with a commercial MEOR process in order to cost-effectively increase oil production.
Treatment goal was to design and implement MEOR in an existing waterflood so that metabolic byproducts of the bacteria produced in reservoir pores, would cause the release of previously immobile oil. The oil release mechanism is similar to chemical solvent and surfactant flooding. Water injection volumes, oil and water production volumes, and hydrocarbon-degrading bacteria (HDB) populations are presented before and after MEOR treatment.
Factors Affecting the Stability of Proppant in Propped Fractures: Results of a Laboratory Study
Authors: Milton-Tayler David , Stephenson Chris , Asgian M. I. 
Published: December 2007

ABSTRACT
Factors controlling the stability of proppant in propped fractures were identified and investigated experimentally. The results indicate that the absolute size, distribution and type of proppant may affect stability, and hence the likelihood of proppant flowback.
The extent of aTbedment of the proppant into the rock (determined by closure stress and rock hardness) was found to play a key role in stabilising the pack. In addition, channels, which may form due to proppant settling before fracture closure, were found to significantly reduce stability. These are, therefore, favourable sites for proppant flowback.
A numerical study has been used to determine lengths of unpropped fractures which may be maintained open due to the rock stiffness. The implications of these results for well productivity and the understood mechanisms of proppant flowback, in the field, are discussed.
Fracturing Pressures for Horizontal Wells
Authors: Owens K. A. , Andersen S. A. , Economides M. J. 
Published: December 2007

ABSTRACT
A fully horizontal well, drilled at an angle from the fracture plane, will experience a potentially substantial increase in the fracturing pressure. The magnitude of this pressure depends on the angle (as the angle increases so does the pressure) and, very importantly, on the value of the intermediate of the three far-field stresses.
Application of these findings to eight horizontal wells in the DAN field and comparison with actual data from several fracture treatments within each well showed an excellent match between predicted and observed fracturing pressures. The results are presented in this paper.
Determination of Fracture Geometry Using Field Data Coupled With a Fracture Simulator
Authors: Martinez A. D. , Pardo C. W. , Ellis P. D. , Pittman R. W. 
Published: December 2007

Abstract
A practical analysis technique for the determination of fracture geometry using actual treatment signals has been developed using a commercial 3D fracture simulator. This simulator allows the use of treatment data as well as reservoir and fluid properties to be incorporated into the determination of fracture geometry. This analysis has been applied to typical, water-based fluid treatments using readily available surface treatment data. Although the simulator has the option to incorporate energized and foam fluids, we have not yet used it to analyze these type jobs due to the lack of treatment bottom hole pressures and temperatures.
The analysis technique has been applied to several treatments in various parts of the United States. The process involves taking treatment data (injection rate, proppant concentration, etc.) and obtaining a history match of the surface treating pressure. Several practical analysis techniques are employed to enhance the confidence in the resulting fracture geometry. In the case where mini-fracture data is available, the mini-fracture treating and falloff pressure responses are matched with the simulator to determine the corresponding reservoir parameters. Using the mini-fracture defined parameters, the main treatment is analyzed and history matched. Based on the resultant fracture geometry obtained from the simulator, future treatment designs can be altered or refined to obtain the optimum fracture geometry for the reservoir.
Hydraulic Fracturing Research in the Frontier Formation Through the Gas Research Institute’s Fourth Staged Field Experiment
Authors: Saunders B. F. , Robinson B. M. , Holditch S. A. , Holditch S. A. , Peterson R. E. 
Published: December 2007

Abstract
The Gas Research Institute (GRI) has sponsored a field based research program through the Staged Field Experiment (SFE) project for the last several years. SFE wells are drilled specifically for conducting research in the analysis and stimulation of tight sands and for validating technologies under development in other GRI projects. The majority of this work was spent in the Travis Peak and Cotton Valley formations in east Texas where the first three SFE wells were drilled. Results of this work have already been published in GRI reports1–3 and SPE papers4–6. This paper summarizes the results from research conducted on the fourth SFE well. This well was drilled in the Frontier formation of southwestern Wyoming. A primary objective of this SFE was to determine if technology developed in previous SFE wells in east Texas can be successfully transferred to ther geologic basins.
In order to fully describe each of the layers of rock on SFE wells, data are collected from whole cores, openhole geophysical logs, in-situ stress measurements, production and pressure transient tests, fracture injection treatments, and fracture diagnostic measurements. These data are then analyzed in detail with advanced formation evaluation techniques, including numerical models, in an effort to obtain the best possible description of the reservoir and hydraulic fracture. On SFE No. 4, there were several new technologies and analysis methods that were being evaluated. Specifically, these techniques to evaluate SFE No. 4 included in-situ stress profiling, fracture height and azimuth analysis, hydraulic fracture analysis, and post-fracture performance analysis.
Knowledge and techniques developed through GRI research programs are designed to benefit the natural gas industry. A better understanding and more accurate analysis of the hydraulic fracturing process will lead to improved treatment designs and additional gas production from tight sands such as the Frontier. A goal of the GRI program is to apply rigorous analysis techniques to evaluate hydraulic fracture treatments in any geologic basin. The SFE No. 4 in southwestern Wyoming illustrates that rigorous analysis techniques can be used to analyze and better understand fracture geometries in complex reservoirs that typify tight gas formations.
Small, Highly Conductive Fractures Near Reservoir Fluid Contacts: Application to Prudhoe Bay
Authors: Martins P. J. , Collins P. J. , Rylance Martin , Ibe O. E. , Kelly R. T. , Bartel P. A. 
Published: December 2007

ABSTRACT
The paper describes the techniques used in Prudhoe Bay to place small, highly conductive fractures in areas of the field where there is no fracture containment to prevent fracture growth into an aquifer.
A reservoir study to investigate the effects of fracturing close to oil water contacts is presented, together with 3D fracture modelling of fractures with no downward containment. The paper highlights the importance of spurt losses in both frac designs and minifrac analyses, when fracturing high permeability reservoirs. A simple minifrac analysis, for use with complex fracture geometries, is provided.
The fracture design methodology is presented, supported by field examples.
Reservoir Evaluation, Completion Techniques, and Recent Results From Barnett Shale Development in the Fort Worth Basin
Authors: Lancaster D. E. , McKetta S. F. , Hill R. E. , Guidry F. K. , Jochen J. E. 
Published: December 2007

ABSTRACTThis paper describes the evaluation, completion, stimulation, and testing of Barnett Shale wells operated by Mitchell Energy Corporation (MEC) in the Fort Worth Basin of north-central Texas. In particular, the paper presents a detailed analysis of data collected from a Gas Research Institute/MEC cooperative research well that was used to gain a better understanding of the mechanisms controlling gas production from the Barnett Shale. The Barnett Shale covers a large geographic area of north-central Texas; thus far, most of the activity is centered around Wise and Denton Counties, TX.On the basis of the data analyzed, the Barnett Shale appears to be characterized best with a layered reservoir description where most of the well deliverability is associated with thin, higher permeability, naturally fractured zones, while most of the gas-in-place is confined to thicker, extremely low permeability layers. Gas-in-place in the Barnett Shale may average 10 to 12 Bscf per 160 acres, but the better wells are expected to recover only 1 to 1.5 Bscf in a twenty-year well life. Approximately 20% of the gas-in-place in the Barnett Shale is adsorbed gas; however, desorption appears to become important only after the reservoir pressure falls below 1,000 psia (original reservoir pressure is about 4,000 psia). Evaluation of fracturing pressures and post-fracture well tests suggests long, propped hydraulic fractures are being achieved and that the hydraulic fractures are typically contained within the Barnett Shale by limestone formations above and below.
From Stochastic Geological Description to Production Forecasting in Heterogeneous Layered Reservoirs
Authors: Hove Kjetil , Olsen Gudmund , Nilsson Stefan , Tønnesen Morten , Hatløy Andres 
Published: December 2007

ABSTRACT
This paper discusses the data transfer from a detailed gridded stochastic geological model to a more coarsely gridded reservoir simulation model. A new gridding technique has been developed to follow the main geological features. This technique makes the transformation between the geological model and the reservoir model more accurate and efficient. It has been successfully applied in field evaluations for a North Sea sandstone reservoir.
The reservoir in question is very heterogeneous. Conventional geological models based on smooth parameter interpolation between well data do not reflect these heterogeneities. A two-stage stochastic geological model was therefore used to represent the reservoir.
In the first stage the geological architecture of the reservoir was constructed. In the second stage petrophysical values were assigned to each building block in the geological model. This two-stage modelling procedure was described by Damsleth et. al.1.
The complete study is reported, from the stochastic geological model via the new gridding procedure and homogenization to simulated production forecasts. The effects of different assumptions in the gridding have been evaluated using both water, gas and WAG injection as well as depletion. A procedure for incorporating the results into the total field production forecast is outlined.
The importance of representing the main geological features in the gridding is demonstrated. When a regular coarse grid was used, the contrasts in reservoir properties were smoothed out by averaging, and in most cases a more optimistic production performance was then predicted.
Detailed stochastic geological models can give more realistic production profiles for the reservoir. In this study the stochastic model resulted in a reduction in recovery compared to conventional models.
A Practical Application of Stochastic Modeling Techniques for Turbidite Reservoirs
Authors: Handyside D. D. , Karaoguz O. K. , Deskin R. H. , Mattson G. A. 
Published: December 2007

Abstract
A detailed study of the productivity and recovery potential for a turbidite reservoir has been completed using a practical application of stochastic modeling and reservoir simulation techniques. The objective of this study was to assess the impact of various reservoir characteristics on development considerations such as well spacing and expected production/recovery profiles.
Distributions of typical sand body dimensions were estimated from a review of core, log, seismic, and analog data. These distributions were input to a stochastic modeling program to generate multiple realizations of reservoir descriptions for a range of net/gross ratios, facies distributions, and assumed sand body geometries. An interface program was developed to minimize the gridding problems associated with conversion of stochastic model output to reservoir simulation input data. Grid data generated from this program were input directly to practically sized reservoir simulation models.
Results from the stochastic realizations and simulation models demonstrated the potential variability in connectivity and recovery profiles that may be expected for a turbidite reservoir. The reduced connectivities in the stochastic model yield significantly different production profiles and lower recoveries than would be calculated with the assumption of continuous layer-cake type models. The approach developed for this study can be used to define and improve confidence limits for production and recovery profiles from typical turbidite reservoirs with only limited well information.
Application of Nonlinear Adaptive Modeling for Rigorous Representation of Production Facilities in Reservoir Simulation
Authors: Stoisits R. F. , Batesole E. C. , Champion J. H. , Park D. H. 
Published: December 2007

Abstract
A nonlinear adaptive modeling technique has been used to encode a rigorous deterministic model for optimal allocation of lift gas to wells. This model was incorporated into the Kuparuk Full Field Reservoir Simulator, for the purpose of evaluating the effect of additional lift gas compression capacity on production from the Kuparuk River Field. Simulation results indicate the nonlinear adaptive model technique yields more accurate lift gas allocations than the prior allocation paradigm which was based on nonlinear regression of field data.