bluuebunny/crossref_metadata_2025_split huggingface dataset:
Interactions of the Horizontal Wellbore Hydraulics and Formation Damage
Authors: Civan Faruk 
Published: December 2007

Abstract
A model for prediction of the formation damage by rock, fluid, and panicle interactions in the porous formation around hydraulically fractured horizontal wellbores considering the effect of the wellbore hydraulics and filtercake is presented. The processes governing the various formation damage mechanisms and the filtercake are represented by the models developed by Civan et al. The wellbore hydraulics model by Sharma. et al is incorporated into the model to take into account for the effect of the wellbore fluid pressure variation on formation damage. The fluid hydraulics in the fractures are represented by extending and modifying the approach by Barree and Conway. For simplification purposes, the two-phase flow through porous media is described by facilitating a unit end-point mobility ratio formulation following Craig, Collins, and Dake. The well, fracture, and reservoir hydraulics are coupled by imposing the well and fracture pressure equations as the boundary conditions for the reservoir by extending the approach by Soliman for the three dimensional case. This model is applied for mud invasion into the near wellbore formation from a hydraulically fractured horizontal well.
Determination of Dispersion and Diffusion of Miscible Liquids in Porous Media by a Frequency Response Method
Authors: Goss Michael J. 
Published: December 2007

Abstract
A new method of measuring molecular diffusion and axial dispersion during miscible displacement in porous media is described. Equal density and viscosity liquids are injected into the porous medium at a constant volumetric rate with a sinusoidal concentration of fixed frequency and amplitude at the inlet. Amplitude attenuation and phase changes are measured in situ along the direction of flow; dispersion is calculated from these frequency response measurements. Molecular diffusion is determined by stopping the flow and recording the transient decay of the concentration sin waves.
Measurements were made in a consolidated sandstone core using mixtures of isopropyl alcohol and deobase. The in-situ concentrations were determined at various positions along the core from changes in dielectric constant. Dispersion coefficients calculated from the standard dispersion equation were found to depend on wavelength, contrary to the basic postulate that the dispersion is frequency postulate that the dispersion is frequency independent. This indicates that the standard dispersion equation is inadequate since, at a given injection rate, the dispersion coefficient will depend upon slug size.
The capacitance model requires data obtained at three different wavelengths for each determination of the dispersion coefficient. mass transfer coefficient, and stagnant volume fraction. Thus, the effect of wavelength on these parameters is not well defined. Experiments using additional wavelengths indicate that the parameters are still frequency dependent, but the variations are smaller and less systematic than those obtained with the standard dispersion model. The dispersion coefficients obtained from the capacitance model are lower than those obtained from the standard dispersion equation.
The main features of the sinusoidal method are that it is a steady-state analysis which may be applied to many models. The time required for the measurements is short relative to the transient methods, and it provides a method of measuring the molecular diffusion in addition to the dispersion from the same experiment.

Introduction
The potential importance of enhanced oil recovery by miscible displacement processes is demonstrated by the large number of studies of diffusion and dispersion of miscible fluids in porous media reported in the literature of the porous media reported in the literature of the last decade. These investigations have almost exclusively employed an assumed step change input followed by analysis of the average concentration distribution at the system outlet as a function of time (breakthrough curves).
Proppant Flowback Control in the Burgos Basin
Authors: Prado-Velarde E. , Sánchez-Bujanos J. M. , Valenzuela A. , Fragachán F. 
Published: December 2007

Abstract
Proppant flowback following a hydraulic fracture treatment, is a major problem in the Northern Mexico area. Frequently, Proppant flows back as the well returns to production. Generating huge amount of cost associated with wellbore cleanouts and damage to surface facilities. In addition, production is delayed due to long shut-in times and the need to initially produce the well under choke.
Therefore, been able to control proppant flowback at fracture closure would not only eliminate the extra expenses associated with it, but would allow to return the well back to production inmediately with optimized chokes. In other words, an optimized proppant free robusted production.
This paper presents successful applications of stabilizing proppant packs with randomly oriented fibers of similar density to the proppant in dry gas reservoirs with low permeabilities (&lt;0.5 md). All wells were put on production immediately following fracture treatment, with an average of almost 2 fold production increase over resin-coated proppant treatments, having a case with up to 12 folds of increase. During "clean-up" of the wells, return fluids were collected for evaluation confirming expected proppant control and fluid compatibility between fracturing gels and breakers. Finally, production performance months after the treatments are discussed including conclusions and recommendations derived from treatments.
Improved Offshore Drilling in the Cretaceous (With Flint) and Jurassic Rock – Mexico
Authors: Ortiz Blas , Martinez Humberto Castro , Garcia Leonardo Martinez , Salinas Juan Gaspar 
Published: December 2007

Abstract
The introduction of a new Polycrystalline Diamond Compact (PDC) product into Mexico's oil market has been shown to help improve drilling time through the Cretaceous (with flint) and Jurassic rock. Through teamwork of various parties involved, the objective of efficiently drilling this difficult formation was accomplished.
This paper discusses specific design features which improved bit selection for this application. Examples of design considerations include bit profile, cutter size and type, cutter density, hydraulic configuration and blade count.
A presentation is given of performance data, operational details and economic analysis concerning use of bit design ultimately selected. This data indicates that an increase in overall drilling performance contributed to the success of economically drilling the Cretaceous (with flint) and Jurassic rock.
Microbial Methods for Improved Conformance Control in Porous Media
Authors: Stepp Anita K. , Bryant Rebecca S. , Llave Feliciano M. , Evans Deanna B. , Bailey Scott A. 
Published: December 2007

Abstract
Water handling is a major expense involved in producing mature oil fields. Reservoir heterogeneities and variations in permeability can aggravate the problem of water production and significantly reduce the efficiency of oil production. Several methods for improving reservoir sweep through conformance control have been used. Methods such as crosslinked polymer technology have alleviated problems associated with reservoir heterogeneity. Other alternatives such as microbial- and surfactant-based methods have been proposed. This paper presents the results of research conducted on polymer-producing bacteria that were isolated and tested at various temperatures and salinities. Coreflooding experiments were conducted to show the effectiveness of microbial treatments. Reduction in effective permeabilities by as much as 90% were achieved due to in situ polymer production. Noninvasive imaging techniques such as magnetic resonance imaging (MRI) and computer-aided tomography (CT) were employed to visualize changes in fluid distribution in porous media. High permeability areas were blocked by biopolymer production, resulting in brine diversion into lower permeability areas.
Hot Water Flooding for High Permeability Viscous Oil Fields
Authors: Goodyear S. G. , Reynolds C. B. , Townsley P. H. , Woods C. L. 
Published: December 2007

Abstract
A number of North Sea reservoirs contain viscous oils in high permeability sands. One possible IOR technique is the injection of hot water using long horizontal wells. A sector model for a high permeability reservoir containing a 400 cp oil underlain by a large aquifer has been constructed. Hot water injection was compared to cold water injection. Hot water flooding can recover significant volumes of incremental oil and extend the economic life of the field. The incremental recovery mechanism is a complex interaction between gravity forces and temperature induced changes in viscosity and density. Improved sweep in some regions is partly offset by oil resaturation of previously swept regions. Thermal expansion of water plays an important role, the lower density of hot water reduces thermal loses to the aquifer and speeds up the propagation of the temperature front through the reservoir.
A risk management study is reported in which sensitivities to well bore friction, kv:kh ratio, heterogeneity and relative permeability are investigated. The optimal choice of the injection well position (different depths in the oil column from the top of the reservoir) is considered for cold and hot water flooding and is shown to be strongly determined by the kv:kh ratio. Significant friction in the horizontal producers and injectors can be detrimental to hot water flooding performance. A Monte Carlo analysis is performed to select the most appropriate well position. This also shows, for a reservoir of this type, that hot water has the potential to add value to a development scheme at acceptable levels of project risk.
Field Scale Simulation Study of In-Situ Combustion in High Pressure Light Oil Reservoirs
Authors: Tingas John , Greaves Malcolm , Young T. J. 
Published: December 2007

Abstract
Air injection may be an efficient EOR process for deep high-pressure light petroleum reservoirs, for example those found in the North Sea area. Based on phase behaviour analysis by a pseudo-compositional approach and combustion tube simulations, comparative reservoir simulation studies have been conducted to evaluate the potential and displacement characteristics of processes in high-pressure, volatile light petroleum reservoirs.
The primary objective of the study is to examine the feasibility of in-situ combustion processes in North Sea type high-pressure, volatile light oil reservoirs. The reservoir operational parameters have been optimized, and the results of this study are useful for screening of EOR processes, as well as the design and interpretation of in-situ combustion projects.
A simulation study has examined the sensitivities of important in-situ combustion parameters on a field scale. Variations in well pattern size, air injection rates and injection fluid (air, O2, CO2, N2 ) were also examined. Techniques were devised to model the combustion process in a large field-size grid. Results from areal and cross-sectional models were combined to obtain a three-dimensional analysis of the fire flood performance for various well patterns.
Simulation runs revealed combustion front extinction problems due to large grid block size expected for well spacing higher than 2.5 acres also with kinetic controlled field scale models. Extinction of the combustion front significantly reduces predicted areal sweep and oil recovery, resulting in shorter project lifetimes. Kinetic controlled field scale models for well spacing lower than 2.5 acres can predict combustion front formation and vaporization of water and light petroleum components, when simulated with commercial simulators having about 200 grid blocks.
The simulations also show that the vertical sweep efficiency is predominately controlled by the vertical permeability variation in the reservoir. The detailed simulation output showed that mass transfer between phases, oil vaporization, cross flow between layers and heat loss to the adjacent formations are important processes in this thermal recovery process.
Front tracking and a thin flame technique are considered to be important for enhancing simulation capability. The development of more advanced non-isothermal simulators with these capabilities will increase the reliability of air-flood simulation predictions in high pressure light petroleum reservoirs necessary to reveal higher recovery potential than predicted by current simulation predictions.
The Improved Oil Recovery (IOR) potential performance of thermal IOR processes, such as air and oxygen injection in-situ combustion processes, is predicted the highest among the alternative options.
Foam Displacement Modeling in CO2 Flooding Processes
Authors: Chang Shih-Hsien , Grigg Reid ?. 
Published: December 2007

Abstract
A foam model based on the foam resistance factor has been developed and has been incorporated into two reservoir simulators. The first is a pseudo-miscible simulator, MASTER, obtained from the Department of Energy, and the second is an equation-of-state, compositional simulator, UTCOMP, obtained from the University of Texas at Austin. Both simulators have been successfully modified to simulate foam flooding processes where the resistance factor data are input as lookup tables. In the validation exercise, an injection schedule that mimics an actual foam field pilot test was used. The simulation results show an increase in the oil production rate, attributed to the effects of foam, and are consistent with the observation from the foam field pilot. The results also show successful profile modification because of the presence of foam, thus resulting in significant sweep improvement. Agreement between MASTER and UTCOMP was good.
Composition of Remaining Oil in a Mature Steamflood
Authors: Richardson W. C. , Deemer A. R. , Nelson C. E. 
Published: December 2007

Abstract
Detailed compositional distributions of remaining oil from cores in Kern River Field steam floods have been characterized to evaluate the effect of steam distillation/condensation on the low Sor (6%) observed in the steam zone, and to bear on the mechanisms of the steamflood process in general. Steam distillation of heavy oils in the 10–14 ° API range has traditionally been thought to have little impact on oil recovery.
Oil compositional analyses have been performed on many recent (1992–94) core samples from temperature observation (TO) wells in Kern River steam floods. Samples were chosen to reflect a range of initial and historical conditions observed in the steamflood at Kern River.
It has been found that the oil composition in the steam zone is depleted and oil near the vapor/liquid interface is enhanced in light to intermediate hydrocarbons relative to the composition of base oil samples. The data show that steam distillation is significant in the steam zone where low Sor (6%) is achieved. The implications of the effect of steam distillation/condensation on the steam flood process based on this data will be discussed.
Development of Dual-Permeability Thermal Simulator and Validation for Yates Field
Authors: Winterfeld Philip H. 
Published: December 2007

Abstract
Conservation equations for single-porosity and dual-permeability transport are similar except for matrix-fracture transport terms. A dual-permeability thermal simulator is developed starting from a single-porosity one by replicating the single-porosity grid, denoting one half of the grid to be fractures, the other half matrix, and introducing connections between analogous gridcells of the two halves that account for matrix-fracture transport. Consequences of replicating the single-porosity grid, which doubles the number of gridcells, are discussed. The dual-permeability simulator was developed to simulate steam injection in the Yates field. A two-dimensional and three-dimensional example of steam injection into a reservoir are shown. The two-dimensional example is used to validate the dual-permeability simulator by comparing results to a single-porosity simulation in which fractures are represented explicitly as narrow slits.
Reservoir Characterization Methodology to Identify Reserve Growth Potential
Authors: Holtz M. H. , Hamilton Douglas S. 
Published: December 2007

Abstract
The information available for characterizing a reservoir is insufficient to develop a unique model. However, by applying the proper reservoir characterization methodology, a model can be constructed that optimizes and integrates all the data and thus facilitates the identification of reserve growth potential. This methodology contains four steps: (1) determining reservoir architecture, (2) establishing fluid-flow trends, (3) integrating reservoir architecture and fluid-flow trends, and (4) identifying reserve growth potential. The key to determining reservoir architecture is the application of generic sequence stratigraphy. The reservoir architecture is determined by ascertaining the internal reservoir stratigraphy, defining the stratigraphic unit geometries, interpreting the distribution of depositional environments, and combining stratigraphy with structural character. Establishing fluid-flow trends should be accomplished within the context of the stratigraphy. This step includes determining the initial fluid properties, generating a production-time-series analysis, analyzing any variation in fluid chemistry, assessing well test data, and determining the direction of injected fluids. The third and pivotal step of integrating reservoir architecture and fluid-flow trends has four steps. It begins with designing geologically based petrophysical models, then concurrently identifying the correspondence between reservoir architecture and fluid-flow trends and establishing reservoir flow units. Next, the petrophysical properties are distributed spatially and the hydrocarbons in place are calculated. The final step is identifying reserve growth potential. It is accomplished by calculating reserves, delineating the remaining hydrocarbon resource, generating reserve growth concepts, and targeting reserve growth opportunities.
Application of Systems Analysis Can Increase Production by 200 Percent in High Volume Gas Lift Wells
Authors: Jones Doyle L. , Brown Kermit 
Published: December 2007

Abstract
Total fluid production and hence oil production can be increased significantly by production can be increased significantly by evaluating and modifying presently installed gas lift system. Many gas lift systems were improperly designed initially, and as a system was expanded, the inefficiencies were compounded. The more critical design features of a continuous gas lift system are tubing sizes, operating gas lift pressure, proper valve design, and surface back pressure. The optimization of any one of these features will improve a system, but the proper design of all four will result in the most efficient system.
This paper will show how production from a 6,000 ft, well was increased from 620 bbl/D to 2,280 bbl/D by optimizing the gas lift system. The effects of changing the tubing to a larger size are graphically illustrated. Streamlining of wellheads, flow lines and separator headers are shown to be a necessity in reducing excessive surface pressure. A discussion of an efficient lift valve design is included. The changing of a gas lift system from some eight valves to fourteen valves and placing them in a so-called stacked condition is one of the more important features in increasing production. A discussion of gas lift valve choke sizes is included as well as the necessity for a high system pressure. In this case, pressure was increased from 900 psi to 1300 psi, thereby providing a lower gas injection point required for maximum production. point required for maximum production. By the proper analysis of a high volume gas lift System, production can be increased as much as 200% by carefully analyzing the following features:
- tubing size,
- operating pressure,
- surface wellhead restrictions, and
- the number and spacing of gas lift valves.
Once a system is considered to be operating at its maximum efficiency, it should not be neglected. Proper monitoring is as important as the initial design and installation. At least bimonthly well production tests should be conducted with complete production information recorded. This then provides necessary information prior to a workover whereby a complete system prior to a workover whereby a complete system analysis can be applied for the purpose of increasing production. production. Many beneficial changes can be made with very little expense if a Proper evaluation is conducted and analyzed.
3D Seismic Calibration to Measure Upper Jurassic Sand Porosity, North Viking Graben
Authors: Lowden D.J. , Hansen P.A. 
Published: December 2007

Abstract
Localized sand bodies can be found encased within widespread Upper Jurassic shales, preserved on the flanks of eroded paleo-highs in the North Viking Graben. They are often situated in structural lows, poorly represented by well control and highly heterogeneous. Moreover, they are difficult to identify using conventional seismic and their location even harder to predict using geological modelling techniques. However, these excellent quality sands provide stratigraphic traps that can be quantitatively mapped using borehole calibrated 3D seismic acoustic impedance.
The Statfjord Nord 3D seismic survey was shot and processed during the last decade. Recently, borehole calibrated processing was performed on the 3D survey to obtain seismic acoustic impedance from each seismic trace. An objective method was used requiring no a priori information to constrain the solution and hence was not dependent upon a geological model.
The 3D seismic acoustic impedance permitted discrimination of Upper Jurassic sands from adjacent shales by virtue of their unique acoustic signature. Sand effective porosity was computed for a subset of the 3D volume using relationships obtained from an acoustic-petrophysical study carried out using well data. The 3D acoustic impedance was converted to velocity, thus allowing the thickness to be obtained for each seismic time sample. This quantitative calibration of 3D seismic made it possible to objectively map porosity-thickness of Upper Jurassic sands.