bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Investigation into Enhanced Recovery under Solution Gas Drive in Heavy Oil Reservoirs
Authors: Kumar R. , Pooladi-Darvish M. , Okazawa T. 
Published: December 2007

Abstract
Some of the heavy oil reservoirs in Western Canada and Venezuela show anomalously high primary recovery under solution gas drive process. Pressure decline rate in these reservoirs is low compared to that expected under solution gas drive in conventional oil reservoirs. Several theories have been proposed for these anomalous behaviors.
The objective of this study is to examine one of the proposed theories, which suggests that gas mobility in heavy oil is low. In this study, gas mobility under solution gas drive is measured by performing depletion experiments. The depletion was carried out at four different rates. The Eclipse-100 Black oil simulator was used to match the experimental data.
The direct results from the experiments show that the critical gas saturation is not very high. Thus, critical gas saturation cannot explain high recovery. However, it was found that the gas mobility in heavy oil is quite low, when compared to that expected in conventional oil.
Experimental results indicated that higher rates of pressure drop resulted in higher super-saturation, higher critical gas saturation and lower relative permeability to gas. Physical explanation of the observed behavior is offered in light of the anomalous behavior of heavy oil reservoirs. An empirical model was developed to predict gas mobility, critical gas saturation and supersaturation as a function of depletion rate for the system studied.
Wall-Effect/Gel-Droplet Model of Disproportionate Permeability Reduction
Authors: Liang J. , Seright R. S. 
Published: December 2007

Abstract
Many polymers and gels can reduce the permeability to water more than that to oil or gas. However, the mechanism of this disproportionate permeability reduction is not clear. This paper considers a promising potential explanation that is based on a combined "wall-effect" and "gel-droplet" model. Disproportionate permeability reduction can be explained by a wall-effect model if the gelant is prepared from or matches the wetting phase, and by a gel-droplet model if the gelant is prepared from or matches the non-wetting phase. The combined model predicts that disproportionate permeability reduction should increase with increasing residual nonwetting-phase saturation. New experimental results support this prediction. Maintaining high residual oil saturations in the treated region of an oil zone could significantly reduce damage to oil productivity after a gel treatment.
The disproportionate permeability reduction increased with increased pressure drawdown between 45 psi/ft to 180 psi/ft. Therefore, to a certain extent, an increase in pressure drawdown after a gel treatment might reduce damage to oil productivity without increasing water production.
Application of Partitioning Tracers for Remaining Oil Saturation Estimation: An Experimental and Numerical Study
Authors: Chatzichristos C. , Dugstad Ø. , Haugan A. , Sagen J. , Muller J. 
Published: December 2007

Abstract
This paper presents the first results of an ongoing experimental work at IFE for developing new tracers to be used for estimation of remaining oil saturation. The methodology is based on the chromatographic theory, which states that various components flowing through porous media will be delayed according to their partition coefficient to the immobile phase. Two experiments, one with gas tracers and the other with water tracers, are presented here, demonstrating the applicability of the methodology in the laboratory scale. Moreover, a numerical model (ITRC-SIM module) developed at IFE especially for simulating the tracer flow in hydrocarbon reservoirs is validated against the experimental data and used to demonstrate the use of tracers in small and field scale generic cases.
A Streamline Approach for History-Matching Production Data
Authors: Wang Yuandong , Kovscek Anthony R. 
Published: December 2007

Abstract
This study proposes and develops a streamline approach for inferring field-scale effective permeability distributions based on dynamic production data including producer water-cut curve, well pressures, and rates. The approach simplifies the history-matching process significantly.
The basic idea is to relate the fractional-flow curve at a producer to the water breakthrough of individual streamlines. By adjusting the effective permeability along streamlines, the breakthrough time of each streamline is found that reproduces the reference producer fractional-flow curve. Then the permeability modification along each streamline is mapped onto cells of the simulation grid. Modifying effective permeability at the streamline level greatly reduces the size of the inverse problem compared to modifications at the grid-block level. The approach outlined here is relatively direct and greatly reduces the computational work by eliminating the repeated inversion of a system of equations. It works well for reservoirs where heterogeneity determines flow patterns. Example cases illustrate computational efficiency, generality, and robustness of the proposed procedure. Advantages and limitations of this work, and the scope of future study, are also discussed.
Support-Operators Method in the Identification of Permeability Tensor Orientation
Authors: Silin Dmitriy B. , Patzek Tad W. 
Published: December 2007

Abstract
The dependence of rock permeability on direction, or permeability anisotropy, is confirmed by numerous field examples. Ability to measure permeability anisotropy is very important for correct placement of wells. There exist several methods of identifying the maximum and minimum permeability coefficients by interpreting specially designed well tests. Here we develop a new method of estimating the angle of orientation of permeability tensor away from the well. We assume that the principal permeabilities near a cored or otherwise logged well are already known. To accomplish this task we need pressure measurements in monitoring wells.
The orientation of permeability tensor is identified by minimizing the square of the differences between measured and computed data. The underlying boundary-value problem is discretized by the support-operators method, which imposes few restrictions on the grid structure; produces a conservative finite-difference scheme and can be applied to very heterogeneous systems. The gradient and second differential of the minimization criterion are obtained through two systems of adjoint equations, called the first and second adjoint systems. The gradient of the criterion is obtained both in continuous and discrete versions. As an illustration, we analyze a steady-state isothermal, single-phase pressure equation in an anisotropic porous medium. A few applications of the technique developed in this paper for rectangular and curvilinear grids confirm good performance of the algorithm.
Automatic Simulation Algorithm for Appraisal of Future Infill Development Potential of Prudhoe Bay
Authors: Farnstrom K. L. , Litvak M. L. 
Published: December 2007

Abstract
The Prudhoe Bay field is a large, mature, Alaskan reservoir. During its 22 year production life, over 40 percent of original oil in place has been recovered. Since beginning decline a decade ago, ambitious fieldwide, infill development has been performed. As the light oil column thins, advanced sidetrack drilling has been employed using coil tubing units and horizontal wells to reach infill targets. The strategy is to accelerate production, to access new reserves, and to replace aging wellbores producing at elevated water cuts and / or GOR's. From 60 up to 100 new completions have been drilled annually in recent years.
This paper reviews the design and application of an automated simulation algorithm constructed to appraise the remaining infill reserves potential of Prudhoe Bay. The algorithm operates in conjunction with a state of the art, full field simulation model (FFM). The FFM is comprised of a reservoir model operating in parallel with elaborate surface pipeline and facilities models. The algorithm is comprised of two modules: an automated drilling routine which drills new infill wells from surface and an automated recompletion routine which sidetracks existing well bores when their productive lifetimes have been reached.
Highlights of the recompletion module include the identification of candidate wells to be sidetracked based upon marginal performance and the location of productive, recompletion targets for each candidate. Well hydraulics for each new recompletion are then defined, and each is connected to the surface pipeline network and to fluid processing facilities. An optimization routine next tests recompletion targets and selects the best performers to be drilled based on the number of sidetracks scheduled for the field. The automated drilling module has commonalties with the recompletion module, and its design and function are also presented in this paper.
The use of the algorithm for the evaluation of various infill development parameters is reviewed. Procedures for analysis of simulation results are presented. Simulation results provide estimates of improved oil recovery from different areas of the reservoir. Rate streams from simulation provide input to economics programs for analysis of program benefits.
Impact of Natural Fractures in Hydraulic Fracturing of Tight Gas Sands
Authors: L. Rodgerson James 
Published: December 2007

Abstract
The presence of natural fractures in hydraulic fracturing candidates can present an array of well completion problems. Natural fractures can be very difficult if not impossible to model without adequate pre-job diagnostic testing to calibrate simulation.
Left undetected natural fractures can cause premature screen-out as well as formation damage. In tight gas sand formations, natural fractures can be the predominate production mechanism in the reservoir. If polymer residue is left in the natural fractures after drilling, stimulation or work-over, a substantial amount of potential production may be left behind. Often this type of damage may be documented by the sheer fact that production may decrease after these types of operations.
Techniques have been perfected to determine the impact on leakoff due to natural fractures. In many cases production may exceed the predictive capability of production simulators without the introduction of permeability numbers that might be considered high for that area. This could lead one to believe that some portion of the production is dominated by natural fractures. A better understanding this type of leakoff could help in the development of methods to predict production results or economics of a well based on pre-job testing.
It is the intention of this paper to discuss methodology to predict the presence of natural fractures and show key considerations when trying to simulate their behavior. This paper will also investigate stimulation problems and damage mechanisms, describing methods that may be used to help minimize their impact.
An earlier version of this paper was presented by this author at the Forty-Sixth Annual Southwest Petroleum Short Course April 21-22, 1999.
New, Lower-Cost Acid Gas Removal and Sulfur Recovery Technology for Permian Basin Natural Gas Production Operations
Authors: Leppin Dennis 
Published: December 2007

Abstract
Technology developments for lowering gas treating and sulfur recovery costs for Permian basin gas have been underway for several years by GRI (formerly Gas Research Institute) and other technology development organizations. Several of these technologies are now nearing the point where commercial applications should be evaluated since significant cost savings and operational simplifications could be achieved by early adopters. After a cursory review of current technology in gas treating and sulfur recovery, this paper summarizes applicable new technology in this area developed by the author's company and others including advances in H2S scavenging, small-scale sulfur recovery up to 15-20 TPD and large-scale gas treating for high acid gas concentration applications.
Seismic Models Enhanced with Well Logs Have Located Sand Rich Areas from South Texas to the Rockies
Authors: Allen Rob L. 
Published: December 2007

Abstract
Seismic models enhanced with well logs help to locate sand concentrations. Many well log curves contain patterns with very high frequencies compared to seismic responses. Quantitative analysis of log patterns can create large numbers of sand vectors for plots that resemble and complement 3D seismic attribute maps. Complex log patterns and improved predictions about changes in log responses over distances have been integrated with broad geophysical coverage. Detailed and extensive reservoir models were created.
Effect of the Wellbore Conditions on the Performance of Underground Gas-Storage Reservoirs
Authors: Tureyen Omer Inanc , Karaalioglu Hulya , Satman Abdurrahman 
Published: December 2007

Abstract
This paper presents results of an underground gas storage modeling study using the reservoir and fluid properties of the Northern Marmara gas field, a recently developed field in the Thrace region of Turkey. It has an area of 3.6 km2 with nearly 3 billion sm3 of GIIP. The reservoir model used in this study is based on the theoretical as well as the empirical deliverability equations. The deliverability equations reflect the production and injection performances of the wells with given completion characteristics.
Our approach is based on maximizing working gas volume for a particular configuration of reservoir, well and surface facilities. The importance of the type of well completion was emphasized in this paper because this is the most likely place for operating problems to occur. The deliverability performance strongly affects the design factors such as the working gas volume and the number of wells operated. Results indicate the performance dependence on wellbore damage and hence the importance of cleanup of wells.
The effects of the mechanical skin factor on the working gas capacity with different number of horizontal wells as well as vertical ones were studied. Results show that the working gas capacity decreases while the mechanical skin factor increases. This behavior becomes especially more dramatic as the horizontal well length decreases. The increasing number of wells increases the working gas capacity as expected. These results are discussed in detail through application to N. Marmara gas reservoir data.
The underground gas storage modelling approach followed in this study is shown to be an effective way to forecast the production / injection performance and to estimate the important design parameters when converting a depleted gas reservoir to a gas storage reservoir. Our approach yields the better understanding of the effect of the wellbore conditions on the performance of the underground gas storage reservoirs as well.
Selection Of Materials For Optimum Performance Of Wellhead Assemblies In Petroleum Production Operations
Authors: Fowler E.D. , Rhodes A.F. 
Published: December 2007

The influence of well fluids and external environments, including offshore and cold weather, on metallic and non-metallic materials is discussed. Methods of selection based on field data, assisted by accelerated laboratory testing, is dealt with in detail Tabulations or material in everyday use are shown, including carbon steels, low alloy steels, stainless steel and elastomers, with suggestions for specific uses.
The selection of materials for petroleum production operations is based primarily on environmental compatibility. cost is an important but secondary consideration. Through the years, users and manufacturers have come to realize that a rather large group of economical materials will serve adequately in a large percentage of fields. Cold weather operations, hydrogen sulfide, carbon dioxide, all influence the need for special materials or routine materials in a different condition.
Chosen materials must be compatible with oil and gas environments as encountered in the production cycle. Well streams contain oils, condensates, methane, carbon dioxide, nitrogen, hydrogen sulfide, ethane, and many heavier fractions plus salt water in varying concentrations and quantities. plus salt water in varying concentrations and quantities. Methane is the least harmful as to its effect on metallic materials.
Table No. I illustrates the effect of individual fractions on metallic materials.
Two basic failure modes are encountered in petroleum production:stress corrosion cracking due to hydrogen production:stress corrosion cracking due to hydrogen sulfide and/or chlorides, andmetal loss in the form of pitting or general corrosion.
pitting or general corrosion. Both failure modes are very important but pitting may be more misleading in that if a corrosion monitoring system is based on well stream iron count, the observer may be content, this while his tubing is being perforated in a zone not of his choosing!
Sufficient data has been accumulated through field experience to permit users and manufacturers to evaluate the problem and make reasonably accurate predictions as to the performance of a material in specific environments. When new performance of a material in specific environments. When new alloys or new applications for established alloys are considered, accelerated laboratory testing can be helpful for screening purposes prior to field testing. purposes prior to field testing. Internal and external accessory items are made from the various materials shown in the tables on the next page.
Table No. 2 and 3 offer several materials in common use for parts wetted by the well stream. parts wetted by the well stream.
Insight into "Agarwal Equivalent Draw-down Time"
Authors: Foster Gary A. 
Published: December 2007

Abstract
A common method in industry to correct pressure build-up data for producing time effects is use of Agarwal equivalent drawdown time (SPE 9289). But how does this correction affect the presentation of data and interpretation when performing well test analysis? It can be argued that a reasonable pressure match to a particular reservoir model can be achieved regardless of how the data is presented. An appropriate match can be quantified by goodness of fit criteria and the best match (model) selected on that basis. Because of the presence of non-unique solutions, it is difficult to know which flow geometry is most appropriate from the match alone. Future flow predictions will be effected by the selection an appropriate model with late time boundary conditions having the largest effect on forecasted volumes. The method presented in this paper will try to reduce the uncertainty when selecting a model to match the pressure behavior plus demonstrate that the Agarwal corrected and Horner corrected derivative are identical.
Modeling Plunger Lift for Water Removal from Tight Gas Wells
Authors: Maggard J. B. , Wattenbarger R. A. , Scott S. L. 
Published: December 2007

Abstract
Many tight gas wells produce at rates below their potential, due to water loading. Plunger lift is often applied to remove produced (or condensed) water, reduce bottomhole flowing pressure, and increase both gas production rate and ultimate recovery. Previous authors have discussed dynamic models of the plunger lift process. However, these previous models considered only stabilized reservoir production. Because of the assumption that reservoir production is stabilized, these older models have only limited applicability to tight gas wells. This paper presents a study of the application of plunger lift to the problem of water removal from tight gas wells. A numerical simulation model was developed which includes gas flow in the reservoir, wellbore/annulus effects, and dynamic plunger lift cycles. Transient reservoir performance is an important feature of the new model. Transient reservoir performance is a significant factor for tight gas reservoirs, especially as average reservoir pressure decreases during the life of the reservoir.
Field data from tight gas wells with plunger lift for water removal can be more thoroughly analyzed using the new simulation model. Calibration of model parameters with field cases allows the plunger lift design to be optimized for a particular well. Improved understanding of the plunger lift process for tight gas wells with water loading problems may lead to more efficient water removal, increased gas production rates and recovery, and longer well life.
Gas Field Optimization: Well Compression Selection Methodology
Authors: Irwin Robert J. , Villavicencio Hector R. 
Published: December 2007

Abstract
To facilitate field and wellsite optimization, Natural Gas producers have come to rely on the strategic placement of compressors to increase production. Mature fields, with depleting reservoirs and/or low wellhead pressures, are ideally suited for this cost-effective gas recovery solution. The decision process by which the production engineer quantifies the placement of a compressor is of significant relevance. There are several strategies available to the production engineer to identify wellsites best suited for optimization. Total Systems Analysis simulation software, Decision Tree Analysis and Real Time Selection Opportunities (RTSO) enable this process. This paper reviews these decision alternatives and the application of the RTSO Risk Matrix to select ideal well compression candidates.
Depletion Performance of Poorly Stimulated Layered Reservoirs Without Crossflow
Authors: McCoy T. F. , Reese D. E. , Johnson P. G. 
Published: December 2007

Abstract
Many layered no-crossflow gas reservoirs when initially completed did not benefit from the use of selective stimulation. Without aid of an effective diversion technique, the stimulation treatment only acts on the high permeability layers. This generally leaves the lower permeability layers in a poorly stimulated condition. Significant upside potential may exist in mature areas through restimulation of the lower permeability intervals.
We present the results of a study of the depletion performance of a two-layer gas reservoir suffering from a poor initial stimulation. We assume that only the higher permeability interval has been successfully stimulated. A 2-D radial simulator is used to investigate the subsequent depletion performance after the low permeability layer is restimulated. Using a graphical presentation of rate versus time and pressure-cumulative production, we illustrate the restimulation effects on the depletion performance of these reservoirs. The graphical presentations clearly illustrate the advantages of re-stimulation as a function of volume ratio, layer skin, and abandonment rate. In addition, a 3-D Cartesian model is used to investigate the restimulation impact in competitive reservoirs. We discuss the magnitude of potential reserve increases and present several field case histories illustrating the restimulation effect. Guidelines for selecting potential restimulation candidates are presented.
Production Performance Evaluation of Hydraulically Fractured Wells
Authors: Poe Bobby D. 
Published: December 2007

Abstract
A detailed analysis procedure for obtaining estimates of the reservoir effective permeability, fracture effective half-length, and average fracture conductivity using the bilinear to formation linear transition regime duration production performance data is presented in this paper. A combination of fractured well diagnostic analyses and history-matching with analytic solutions are used to obtain reliable estimates of the average fracture properties and reservoir effective permeability. The transient performance models reported in this paper include the practical reservoir effects of dual porosity, reservoir permeability anisotropy, and fracture face skin effect.