bluuebunny/crossref_metadata_2025_split huggingface dataset:
Water Movement Surveillance with High Resolution Surface Gravity and GPS; A Model Study with Field Test Results
Authors: Brady J. L. , Wolcott D. S. , Daggett P. H. , Ferguson J. F. , Hare J. L. , Aiken C. L. V. , Balde M. , Seibert J. E. , Mader G. 
Published: December 2007

AbstractA unique method to monitor gas cap water movement in an Arctic environment has been developed and tested. The novel surveillance technique for monitoring the water movement had to be developed given the very limited number of wells that penetrate the gas cap. Conventional fluid monitoring techniques require drilling numerous observation wells to adequately monitor water movement. Modeling studies indicate that density changes associated with water replacing gas can be detected using high-resolution surface gravity measurements. Modeling gravity effects of water movement mass distribution, mass balance and water front detection are discussed. A test of the gravity meter and essential high precision station positioning under typical Arctic winter conditions is evaluated using the Global Positioning System (GPS).Modeling results have shown the general shape of the water front can be detected using surface gravity with μGal precision. With high precision gravity measurements, greater than 90% of the increased water can be accounted for in the resulting gravity anomaly. These estimates include reasonable assumptions concerning the noise level in the measurements of both the gravity data and the location data using the Global Positioning System (GPS). The average water front can be reliably detected within a producing well spacing (approximately 2000 ft (610 m)). Surface gravity and GPS data were gathered over the Arctic Ocean in typical winter conditions (-44° F) accurately enough to monitor the water movement (surface gravity = ±5 μGals: GPS = ±1 cm elevation). In fact, this was the first high precision gravity survey using a GPS antenna as an integral part of the surface gravity meter housing.
Horizontal Well Applications in a Miscible CO2 Flood, Sundown Slaughter Unit, Hockley County, Texas
Authors: Guillot Stephen N. 
Published: December 2007

Abstract
Horizontal wells were seen as a potential way to improve CO2 flood economics by increasing injection rate and improving areal sweep. The effect of horizontal injection wells on vertical sweep in a layered reservoir needed to be determined. Texaco planned to drill two horizontal CO2 injection wells as a pilot. Nearby observation wells would be used to monitor flow in the reservoir.
More wells were planned as a result of a decision to not operate a CO2 flood in a densely populated area. Seven wells in the city of Sundown were plugged and abandoned. Three horizontal producers and one horizontal injector were drilled directionally from locations outside town to replace the plugged wells.
This paper summarizes the planning, implementation, and post-drill analysis of these six wells. The seventh and eighth wells have recently been drilled and are mentioned briefly.
Behavior of Water Cresting Under Horizontal Wells
Authors: Permadi P. , Lee R. L. , Kartoatmodjo R. S. T. 
Published: December 2007

Abstract
Complex reservoir flow problems could be better understood through a study using physical models. The purpose of this paper is to present results of an experimental study of water crest behavior under horizontal wells. This work is made in an effort to better understand the formation and growth of water crest prior to and after water breakthrough. The physical model constructed differs from others in that variation in length and position of the horizontal well can be made. Eighteen different systems with varied oil column thickness and oil viscosity were run. Particularly in systems with viscous oil, the bottom water never reached the tip end of the well even at a producing water cut of almost 100 percent. The end effects defined as the unswept oil are pronounced as the well length is reduced and as the oil viscosity is increased. Also, at high water cut, the portion of the wellbore with low productivity increases with well length. These physical occurrences have not been previously reported. Postbreakthrough performance will be presented and discussed.
Exchange Of Producing Properties To Improve Operating Efficiency, Establish Capital Value Of Reserves And Reduce The Need For Depletion Allowance
Authors: Slobod Robert L. 
Published: December 2007

Abstract
Recent changes in the federal tax law regarding depletion allowance focus attention an the taxation problems of oil and gas production. In this paper we present the idea production. In this paper we present the idea of exchanging (selling) producing properties among operating companies in order to improve operating efficiency. As a result of such exchanges and in addition to the engineering advantages, a capital value for the reserves in the ground will be established for each purchase. In this way, a taxable deduction purchase. In this way, a taxable deduction will be clearly established. We should also realize that the seller will become liable f a capital gains tax when he sells at a profit An important finding is that the higher the price paid in the exchange, the better is the price paid in the exchange, the better is the tax picture. Not only is the tax liability converted to a capital gain situation, but if the price is high enough, a paper loss will be established which will further help the tax picture. This idea is presented with the aim picture. This idea is presented with the aim that it be given further thought and evaluation by the industry as a means of making the industry less dependent upon the depletion allowance for fair taxation.

Introduction
Efficiency in the production of oil could be improved in many reservoirs if the operator could consolidate his holdings. Such a consolidation could be achieved by selling the many isolated leases in different fields and in turn purchasing groups of adjacent or nearby leases in the same producing horizon. In this way more efficient production units could be assembled.
Such lease trades will also have serious and perhaps beneficial effects on the tax obligations of the operator. For example, any gains resulting from the sale of a lease will probably be eligible for the benefits of probably be eligible for the benefits of long-term capital gains. Also, as a result of the purchase of a lease, the operator will have purchase of a lease, the operator will have established a capital value for the reserves. This action will somewhat decrease the dependence on the depletion allowance for fair tax treatment with respect to taxing capital. The effect of the transfer of producing properties on tax obligations and, in particular, its relationship to the depletion allowance is the main subject of this paper.
The subject of depletion allowance is prominent in our thinking these days because of prominent in our thinking these days because of the current changes in the tax laws. By way of review, we should recall that depletion allowance has two main justifications. The first is to encourage exploration. We shall not be dealing with this objective in this discussion. The second purpose is to avoid taxing capital. We should recall that it is part of the tax philosophy in this country that the income tax philosophy in this country that the income tax should not be a tax on capital.
Gas Condensate Reservoir Behaviour: Productivity and Recovery Reduction Due to Condensation
Authors: Barnum R. S. , Brinkman F. P. , Richardson T. W. , Spillette A. G. 
Published: December 2007

ABSTRACT
The depletion of gas condensate reservoirs to pressures below the dew point has been studied by reservoir engineers for many years. Pressure decline below the dew point pressure causes condensation to occur which creates a hydrocarbon liquid saturation in the reservoir. This process reduces liquid recovery and may reduce gas productivity and gas recovery. Exxon experience, particularly in low-productivity, high-yield gas condensate fields, suggests that liquid condensate formation can result in severe loss of well deliverability and therefore of gas recovery. This study was undertaken to evaluate the historical frequency and severity of productivity impairment due to near-wellbore condensate buildup and to identify reservoir parameters associated with severe productivity and recovery reduction.
This study of gas condensate reservoirs included a survey of Exxon and published industry experience, a review of published laboratory data, and simulations with single well flow models. Data from 17 fields are included in this paper to demonstrate that severe loss of gas recovery occurs primarily in low productivity reservoirs. Production data from two wells were history matched with simple radial models to evaluate the potential range of the critical condensate saturation (the minimum mobile condensate saturation) and its impact on gas recovery. Published laboratory data for gas-condensate relative permeability were used as a starting point for these simulations.
The primary conclusion from this study is that productivity impairment results in reductions in gas recovery for wells with a permeability-thickness below 1000 md-ft. The history matched simulations support a range of critical condensate saturations from 10% to 30%, in good agreement with published laboratory values.
Correlations for Liquid Densities and Evolved Gas Specific Gravities for Black Oils During Pressure Depletion
Authors: McCain William D. , Hill Nathan C. 
Published: December 2007

Abstract
Two new correlations are presented. The first correlation can be used to estimate the changes in density of a reservoir oil as reservoir pressure declines and gas evolves from solution. The second correlation can be used to estimate the changes in specific gravity of the gas evolved during the depletion process. Both correlations require normally available field data.
Influence of Temperature, Pressure and Molecular Weight of Hydrocarbon Components on the Multi-Phase Equilibria of Hydrocarbon/Water systems
Authors: Chawla I. S. , Barrufet M. A. , Rahman S. , Beladi M. K. , Wu C. H. 
Published: December 2007

Abstract
We have performed three-phase separation experiments for different multi-component hydrocarbon/water systems for hydrocarbon component varying from C1 to C20. Experiments were done on two different experimental setups. PVT-VLLE apparatus can provide on-line compositional analysis and phase volumes of all phases for temperatures up to 350 °F and Isochoric Steam Distillation Cell (ISDC) can provide only vapor phase compositions, but it can be used up to 500 °F. The experimental results from these cells were compared with results from an equation of state simulator (VLLESIM) and are found to be in excellent agreement. VLLESIM is then used to study the effect of temperature, pressure and molecular weight of hydrocarbon components on multiphase equilibria of different hydrocarbon/water systems.
The Material Balance Approach vs Reservoir Simulation as an Aid to Understanding Reservoir Mechanics
Authors: Ali S.M. Farouq , Nielsen R.F. 
Published: December 2007

Abstract
Recent years have witnessed great strides in reservoir simulation techniques. Numerous reservoir simulators have been developed, and are being employed in comprehensive reservoir production optimization studies. With increased emphasis on total simulation employing mathematical models, one cannot help wondering whether the classical material balance methods are passe. The present article attempts to demonstrate the value of material balance type studies as aids to gaining an understanding of oil reservoir behavior. The generality of the material balance approach is discussed, that is, the employment of a single material balance equation, but in certain prediction calculations, different saturation equations prediction calculations, different saturation equations for different combinations of the basic oil production processes, i.e. gas cap expansion (with production processes, i.e. gas cap expansion (with gravity segregation, with or without counterflow), solution gas drive, and water drive. Limitations of this method, as well as certain complicating features are pointed out. Both integral and differential forms of overall material balances are discussed, and some of the basic characteristics of each, which are often overlooked, are brought out.
The value of the material balance approach vs. numerical simulation is discussed, and the chief advantages of each technique are pointed out using specific examples. It is suggested that the material balance approach, presented with the unified concept proposed here, will continue to be of value in gaining a basic understanding of oil reservoir production processes, and their mutual interactions.

Introduction
The most important development in petroleum engineering during the last decade has been the extensive use of reservoir simulators for simulating complex problems which could not have been solved by conventional material balance methods. The value and the degree of sophistication of such simulators will increase in the years to come. At the same time we believe that the material balance approach will continue to be a valuable tool in gaining an understanding of reservoir mechanics. It is particularly useful as a teaching aid, especially with the unified concept discussed below, which helps to show both its advantages and limitations. The chief objective of the present article is to discuss some of our experiences with teaching advanced reservoir engineering both from the classical and the simulation points of view.
Geologic Properties that Affect Waterflooding in the Big Injun Sand of West Virginia
Authors: Watts Royal J. , Overbey William K. 
Published: December 2007

Abstract
This study was made to determine the petrography, mineralogy, porosity, and petrography, mineralogy, porosity, and permeability of the sandstone, and their permeability of the sandstone, and their relationship to waterflooding in Big Injun reservoirs. Rotary cores, geophysical well logs, petrographic thin sections, and results of chemical analyses of sandstone samples from several Big Injun oil reservoirs were used to determine these parameters. The results show a great range of reservoir characteristics within area of study.
The petrography of the sandstones ranges from lithic graywackes (very shaly), to protoquartzites (clean), with varying mineral protoquartzites (clean), with varying mineral constituents. Porosities and permeabilities also vary greatly due to the petrography and mineralogy of the sandstone. Interstitial clay minerals constitute from less than 5 to more than 25 percent of the reservoir rock. Other important interstitial constituents of the Big Injun sand are secondary precipitated carbonates and quartz. The framework of the Pocono Big Injun sand is composed mainly of Pocono Big Injun sand is composed mainly of quartz grains with minor amounts of rock fragments, heavy minerals, and feldspar.
The interstitial clays and cements in the Big Injun sand have greatly reduced the original porosity and permeability of many of the porosity and permeability of many of the reservoirs studied, and will dictate water-flooding techniques that must be used for successful operations. Laboratory results show that the permeabilities of most Big Injun sands are reduced more than 50 percent by flooding with fresh water as compared with results after flooding with saline water. Several Big Injun sand pilot waterfloods in which fresh surface water was used have been unsuccessful, partly due to low injection rates caused by reduced permeability and pore plugging of the formation. permeability and pore plugging of the formation. Any future Big Injun waterflood projects should use saline formation water in a closed system to reduce interaction between flood waters and the interstitial constituents of the formation.

Introduction
Reserves of premium quality Pennsylvania grade crude oils are steadily being depleted. The refining capacity for Penn grade crudes is increasing and will soon place additional demands on the supply. Much of this additional crude must be produced by secondary-recovery techniques such as waterflooding.
The Bradford area oilfields in Pennsylvania and New York have been successfully waterflooded since 1920.
Virtual Measurement in Pipes: Part 1—Flowing Bottom Hole Pressure Under Multi-Phase Flow and Inclined Wellbore Conditions
Authors: Ternyik J. , Bilgesu H. I. , Mohaghegh S. , Rose D. M. 
Published: December 2007

Abstract
Pressure drop prediction in pipes is an old petroleum engineering problem. There is a long history of attempts to develop empirical correlations to predict the pressure drop in pipes. Some of these attempts have produced correlations that provide good prediction in some cases. However, their general applicability is question-able. Correlations that address only a specific class of problems exist. These types of correlation usually perform better than those which attempt to meet the need of av ariety of problems. Usually, the higher the_ number of variables in the model the lesser the reliability and general applicability of the correlations. This is the result of using methodologies such as conventional regression analysis. In such methodologies, the chances of correctly and completely captwing the relationship between variables decreases as the number of variables increases. Many parameters could be involved in these types of problems, such as gas-oil ratios in two phase systems, water flow in three phase systems, and inclination angles of the pipe, to name a few. In this paper, the authors introduce a new methodology for developing prediction models for pipes. This methodology, which has been named Virtual Measure-ment in Pipes (VMP), incorporates the cutting edge of infmmation technology, artificial neural networks (ANN), to address the development of tools to predict pressure drops in pipes and optimum design of pipelines under a variety of circumstances.
The fimdamental problem with conventional approaches resides in the inherent sequential and point wise (as opposed to parallel and distributed) information processing methods used in development of such correlations. Because of this short coming, conventional methodologies are unable to address, defme, or unravel the highly complex relationships between many variables involved in the process. In this paper, artificial neural networks are used to develop a Virtual Measurement Tool to survey flowing bottom hole pressure in multi-phase systems using information such as oil, gas and water flow rates, temperature, oil and gas gravity, pipe length, swface pressure, and inclination angles of the pipe. The developed Virtual Measurement Tool has been applied to the published field data for flowing BHP predictions. VMP's predictions are com-pared to existing methods and the enhancement is clearly demon-strated.
The developed VMP tool can be applied to wellbore hydraulic problems. It can address three-phase (oil, water, and gas) flow in well bores. This tool applies to a variety of wells, including vertical wells and those with various degrees of inclinations.
Virtual Measurement in Pipes: Part 2-Liquid Holdup and Flow Pattern Correlations
Authors: Ternyik J. , Bilgesu H. I. , Mohaghegh S. 
Published: December 2007

Abstract
The prediction of liquid holdup and multiphase flow regimes present in a well or pipeline is very important to the petroleum industry. Liquid holdup, defined as the fraction of pipe occupied by liquid, and flow regimes must be predicted to design separation equipment and slug catchers in pipeline operations properly. It is also important when designing gas storage fields in depleted oil reservoirs.
A new methodology was developed to model multiphase flow conditions for pipelines and wellbores using only known surface data, This methodology, which has been named Virtual Measurement in Pipes (VMP), incorporates an innovative use of information technology and computational intelligence, to address the development of tools for the engineer to use in the design process for a variety of conditions. Artificial neural networks (ANN) were used to develop a Virtual Measurement Tool to survey the liquid holdup and flow regimes in nonspecific multiphase flow systems using readily available data.
The VMP methodology was tested for validity by comparing virtually measured values with published measurements, As a result, the method proved to be an accurate virtual measuring tool to predict liquid holdup and flow regimes in multiphase flowing pipelines and wellbores, The VMP methodology also demonstrated an enhancement to existing industry recognized correlations.
The Impact of Friction Factor on the Pressure Loss Prediction in Gas Pipelines
Authors: Bilgesu H. Ilkin , Koperna George J. 
Published: December 2007

Abstract
Gas pipeline design is greatly affected by the amount of a pressure drop anticipated during different phases of natural gas transportation. The outlet pressure can be computed by a common gas pipeline equation such as Weymouth or Panhandle formulas at the desired flow rate and pipe size. In addition to selecting the proper size of a pipeline, the compressor capacity and the related cost are determined based on the discharge pressure. The flow rate, in these equations, is defined in terms of a turbulent friction factor. The fiiction factor relationship approximates the turbulent behavior as a :fi.mction of surface roughness in the pipe. An efficiency factor is employed in the equations for adjusting deviations in the pressure drop calculations. Existence of a sub layer, due to the pipe surface condition and accumulations of condensate, can generate cases that cannot be defmed properly by the use a single friction factor. The proper sizing of a pipeline can be improved by defming the ranges of errors introduced with the use of different friction factors.
Different correlations exist for the calculation of the friction factor, f, as a function of Reynold's number and the relative roughness of the pipe. The formulas for f either require an iterative procedure or may be solved explicitly. Also, each friction factor correlation exists with its own valid limits regarding Reynold's number and relative roughness. Thus, some equations are simple to use but not accurate and some are accurate but not easy to incorporate into the fmal equation.
In this study, the effect of the friction factor on the pressure drop calculations for gas flow is presented. Various correlations for friction factors are utilized to demonstrate their impact on the design of natural gas pipelines. Also, a summary and a comparison of results are presented for different flow rates, pipe sizes, and for field data.