bluuebunny/crossref_metadata_2025_split huggingface dataset:
Whole-Core Analysis Methods and Interpretation of Data from Carbonate Reservoirs
Authors: Bynum R.S. , Koepf E.H. 
Published: December 2007

Introduction
During recent years reservoirs where the hydrocarbon storage capacity and the permeability characteristics are due chiefly to fractures and vugs, and tight formations with non-homogeneous porosity development, have become of major importance in West Texas oil production. Diamond coring equipment and methods were devised which permitted excellent recovery of cores from these formations. Examination of these cores with erratic porosity development frequently indicated individual fracture or vug volume greater than the "perm-plug" sample normally used in conventional analysis. It is evident that actual reservoir properties are more closely approached in the sample as the sample size is increased and that the entire core from this type of formation should be analyzed.
Although the literature on general whole-core analysis procedures has been rather limited many innovations have been introduced, both in methods of analysis and in the interpretation and application of the data. The experienced core analyst has determined a set of optimum conditions which permit a confident approach to his specialized work. These optimum conditions include a completely cored interval, beginning several feet above the pay zone, cut with large diameter coring equipment at maximum speed in a properly selected drilling fluid, pulled to the derrick floor in minimum time, described and logged by an experienced man, properly preserved by quick-freezing in dry ice or by sealing in plastic or other suitable means, and delivered immediately to a well-equipped laboratory where the tests are made on maximum-sized samples. Current coring equipment and practices permit a close approach to these optimum conditions.

Coring and Sampling of Core
Although the successful application of the diamond bit was a great step forward in the coring of dense carbonate reservoirs, there still is no means available to recover a sample of the reservoir in an undisturbed condition. Normally, the drilling mud filtrate flushes the core to an irreducible oil saturation. As the core is brought to the surface, the gas in solution in this residual oil is evolved, expands and expels oil and water until liquid saturations are reduced to the point where only gas will flow. The core, as recovered at the surface, then, contains residual oil after water flushing and solution gas drive, some original water and some mud filtrate, and solution gas from the oil. There appears to be a relationship between the formation volume factor of the oil and the efficiency of liquid expulsion by the gas as it expands with pressure reduction.
Quality Assurance Tool for PVT Simulator Predictions
Authors: Varotsis N. , Gaganis V. , Nighswander J. 
Published: December 2007

Summary
The currently available pressure/volume/temperature (PVT) simulators predict the physical properties of reservoir fluids with varying degrees of accuracy depending on the type of model used, the nature of the fluid, and the prevailing conditions. Nevertheless, they all exhibit the significant drawback of lacking the ability to estimate the quality of their answers.
Artificial Neural Networks (ANNs) trained by large PVT databases are increasingly used to provide accurate predictions of physical properties mainly because of their ability to learn from experience. The use of such models offers the unique capability of estimating the quality of their predictions, as the degree of competence can be evaluated for each unknown test case. The accuracy of the ANN-based PVT simulators depends heavily on the density of the database compositional mapping around the coordinates of the unknown reservoir fluid. Unknown test cases found outside the available training space may lead to poor predictions.
In this work, a quality assurance tool is presented that is integrated to the PVT Expert,* which is an ANN-based PVT properties prediction model. In the case of an unknown fluid, this tool qualifies the predictions of the PVT simulator based on the evaluation of the affinity of the test case with the training data sets contained in the database used. Subsequently, the competence with which the ANN model has learned the general trend in the area around any new test case is assessed numerically through the development of one ANN sextuple model per property. Finally, the use of the average predicted value eliminates the risk of considerable deviations.
This innovative approach was tested successfully against a large set of studies unseen by the ANN model. The ability to provide confidence for the accuracy of the PVT predictions and to assess their quality significantly upgrades the applicability of the PVT simulator as a valuable reservoir management tool.
Modeling In-Situ Scale Deposition: The Impact of Reservoir and Well Geometries and Kinetic Reaction Rates
Authors: Mackay E. J. 
Published: December 2007

Summary
Previous work has demonstrated how and where the mixing of incompatible brines occurs in waterflooded reservoirs and what the impact on scale prevention strategies is in terms of timing and placing squeeze treatments. This paper extends this work by modeling the resulting in-situ deposition process. The location of maximum scale deposition and the resulting brine compositions at the production well are calculated for a range of sensitivities, including reservoir geometry (1D, 2D areal and vertical, and 3D), well geometry (location and orientation within the field and with respect to other wells and the aquifer), and the reaction rate (ranging from no precipitation to equilibrium).
In conventional systems with no aquifer, it is demonstrated that maximum scale deposition occurs in the immediate vicinity of the production wellbore; therefore, low produced-cation concentrations indicate inadequate squeeze treatments. In systems in which water injection is into the aquifer, low cation concentrations may also result from deposition deeper within the reservoir. Maximum scale dropout still occurs as the fluids approach the production well but is sufficiently far from the wellbore to be unaffected by squeeze treatments or to have any major impact on productivity. The reaction rate is critical in determining the amount of scale deposition; however, even under equilibrium conditions, sufficient concentrations of scaling ions are delivered to the production well to necessitate squeezing it but with lower inhibitor volumes. Once cation concentrations have been reduced, it is predicted that they will never increase again.
This paper also discusses some of the limitations of modeling such systems, including determination of kinetic reaction rates, mixing zone size, and impact on permeability. Although the thermodynamics are fairly well understood, the kinetics are much more difficult. The size of the mixing zone is affected by numerical dispersion, and computationally intensive techniques are required to overcome this problem. Previous experience shows that formation damage factors are very difficult to extrapolate from coreflood data because there is a great difference between the dimensions of the mixing zone in the reservoir and the core plug.
New Calibration and Conversion Techniques for Radioactivity Logs
Authors: Mercier V.J. , Redford W.H. 
Published: December 2007

Abstract
A new approach to an old problem has made it possible to analyze and quantitatively evaluate a radio-activity log in a relatively short time, whereas in the past it was necessary to calculate and plot a "neutron-derived porosity curve" then transpose that information to other logs.
The new calibration technique is discussed and introduces the terms "radiation units", "environmental units" and "well strata index". The application of these units to each radioactivity log, regardless of detector type, source spacing or well condition, is explained and illustrated.
Neutron curve conversion charts are introduced. The accompanying charts provide a means for comparing neutron curve responses obtained under empty or liquid-filled openhole (uncased borehole) conditions, in borehole ranging from 4 to 9 in. in diameter, with several types of neutron logging instruments operated at various source to detector spacings.
Given the neutron curve response under one set of borehole conditions the charts may be used to determine the response which would be obtained in similar rock under a different set of borehole conditions. In this way the neutron curve of a given well may be converted to obtain the curve which would have resulted had the borehole conditions been altered. Similarly, several neutron curves obtained under different well conditions may be converted to a common basis to determine whether or not certain formations observed in the several wells are alike.
Two-Phase Flow Performance for Electrical Submersible Pump Stages
Authors: Pessoa Rui , Prado Mauricio 
Published: December 2007

Summary
Two-phase flow behavior prediction for centrifugal pumps is a difficult task because of the complexity involved in modeling multiphase flow inside turbo machines. An experimental study has been conducted at the U. of Tulsa Artificial Lift Projects (TUALP) with a 513-series, 22-stage, mixed-flow-type pump to gather data for pump performance under two-phase flow conditions. Air and water were used as the working fluids. This study differs from other experimental works because the pressure changes were recorded stage by stage. The results of previous works have been reported as an average of the intake and discharge conditions and depend on the number of stages used.
Phenomena such as surging and gas locking were observed during these tests, and their boundaries have been mapped.
The pressure increment and total hydraulic horsepower for the average pump, those per stage as a function of the liquid flow rate, and each gas flow rate considered are presented. The pump's average brake horsepower and efficiency also are plotted for the variables mentioned.
The results indicate that average pump behavior is significantly different from that observed per stage.
A New Technique for Examination of Oilfield Brines
Authors: Aycock W.P. , Hough E.W. , Crawford George W. 
Published: December 2007

Abstract
Forty oilfield brines have been examined so far by a polarographic technique new in petroleum engineering called the "tensammetric method" by the team of biochemists who perfected its use in their field. Samples of brine were obtained from various oil fields in which the wells were known to be producing fluid from oil productive zones in well-known geologic formations. Most of the reservoirs from which the samples were obtained are believed to have an active water drive under the prevailing conditions of operation. The 40 samples represent brines produced from 16 different formations of various geologic ages.
Graphs have been prepared of the data obtained in the testing of each sample, and the distinctive wave-like curves so obtained are characterized by reproducible profiles, called "response curves." Careful comparison of the response curves of salt water coming from different fields producing from the same geologic formation reveals that the curves are similar. The response curves of salt water coming from productive zones of different geologic formations are characteristically different.
Preliminary work offers the further hope that response curves of an oilfield brine indigenous to a particular oil-bearing formation and hence representative of a particular geologic environment, such as depositional and all subsequent morphological conditions, may be of value in reservoir engineering in the interpretation of surface and interfacial phenomena. For example, the wettability of the rock matrix and more specifically, the classification of productive oil-bearing strata as hydrophyllic or hydrophobic may be determinable. However, many more brines must be examined and the resulting response curves analyzed in comparison to known causal phenomena before this objective is achieved.

Introduction
One of the perennial moot questions in the literature of petroleum engineering is whether the reservoir rock is oil- or water-wet. Possibly an answer to this question could come from a careful examination of oilfield brines. None of the conventional methods of examining brines (chemical analysis, pH and electrical conductivity measurements, and the like) answer the question. Careful analysis of reservoir behavior observed in the exploitation of oil fields, particularly in the application of fluid injection, has been fruitful to the extent that a few reservoirs are believed to be properly classified.
Precise Well Placement With Rotary Steerable Systems and Logging-While-Drilling Measurements
Authors: Tribe I. R. , Burns L. , Howell P. D. , Dickson R. 
Published: December 2007

Summary
This paper demonstrates profitable geosteering of a central North Sea, U.K., horizontal well with a rotary steerable system (RSS) together with new-generation azimuthal logging-while-drilling (LWD) tools. The nature of the tertiary turbidite reservoir, with only 3 million STB, meant that to be commercial, only one horizontal well should be drilled and that the following criteria had to be met.
Maximize standoff from an oil/water contact (OWC) within a sand unit with an approximately 50-ft oil column. Achieve 1,500 to 2,000 ft of good-quality reservoir. While maintaining standoff from the OWC, make a corresponding azimuth turn to follow the crestal dome structures of the reservoir trap. Avoid the risk of stuck pipe by carefully monitoring real-time drilling and well data and by using RSS technology.
During well drilling, correlation software enabled comparison of offset-well and real-time LWD data and visualization of the well's position in the reservoir sequence. This modeling complemented wellsite biostratigraphic and geological correlation work and enabled changes to the trajectory to be planned, which were then achieved while constantly rotating with the RSS. Azimuthal-density measurements were used in real time and as post-well image logs for structural dip and fault interpretation.
The well was geosteered into a sweet spot within 5 ft of the reservoir roof and as much as 56 ft from the OWC. The RSS completed the well in a single 3,844-ft run, with an average rate of penetration (ROP) of 68 ft/hr and no stuck-pipe problems. The target of 1,500 to 2,000 ft of pay was met with 1,980 ft of &gt;20% porosity sand and 88% net to gross. The preplanned geometric wellpath would have missed the first 1,000 ft of the reservoir section, justifying the geosteering approach. A water saturation of 10% was much lower than prognosed, and the well has produced more oil than expected without early water breakthrough.
This well demonstrates the combinability of the latest RSS and LWD technology to meet ever-demanding drilling and geological objectives successfully under circumstances of high economic risk and to ultimately maximize potential well production.
Determination of Fractal Parameters of Fracture Networks Using Pressure-Transient Data
Authors: Flamenco-López F. , Camacho-Velázquez R. 
Published: December 2007

SummaryThe objective of this paper is to investigate the transient pressure behavior of naturally fractured reservoirs with fractal characteristics. This work is based on the findings of previous studies, which have shown that the networks of fractures in some reservoirs are fractals. Thus, using this assumption, an approximate analytical solution for dual-porosity systems is derived in the Laplace space.The approximate solution presented in this work uses a pseudosteady-state matrix-to-fractal fracture transfer function. This solution is compared with a finite-element solution, and good agreement is found. Short- and long-time approximations are used to obtain procedures in time to determine some fractal parameters. These approximations are compared to the appropriate expressions when an unsteady-state matrix-to-fractal fracture transfer function is used.Synthetic and field examples are presented to illustrate the methodology proposed in this work.This paper also presents an analytical solution for the pseudosteady-state flow period and demonstrates the importance of analyzing both transient and pseudosteady-state flow-pressure data for a single-well situation to fully characterize a naturally fractured reservoir with a fractal geometry.
The Role of Surfactant Precipitation and Redissolution in the Adsorption of Sulfonate on Minerals
Authors: Somasundaran P. , Celik M. , Goyal A. , Manev E. 
Published: December 2007

Abstract
The presence of maxima and sometimes minima in the adsorption isotherms of surfactant on minerals has been attributed to various mechanisms involving micelle exclusion, impurities, surfactant composition, mineral morphology, etc. This study on the precipitation of sulfonates with various inorganic ions (Na, K, NH4, Ca, Mg, and Al) and the subsequent redissolution when the surfactant concentration is increased shows a precipitation maximum to occur in the same surfactant concentration range where an adsorption maximum is obtained. Simultaneous abstraction, precipitation, and adsorption experiments have been conducted using chromatographically purified dodecylbenzenesulfonate and Na-kaolinite, and the results show the "abstraction vs. surfactant concentration" curves to exhibit a much more pronounced maximum than the real adsorption (abstraction minus precipitation) maximum. We suggest that the total abstraction of surfactant from the solution on contact with mineral phase, usually called "adsorption," is a summation of both the "real" adsorption and precipitation and that the precipitation/redissolution phenomenon is one of the major reasons for the adsorption maxima. Introduction of oil into the system reduces the precipitation because of partitioning of the sulfonate between the oil and aqueous phases. Precipitation and adsorption data are used to derive possible mechanisms for the precipitation/redissolution phenomena.
Model Studies of the Depletion of Two-Phase Geothermal Reservoirs
Authors: Pruess K. , Bodvarsson G. S. , Schroeder R. C. , Witherspoon P. A. 
Published: December 2007

Abstract
The simulator SHAFT79 of Lawrence Berkeley Laboratory has been used to study the depletion of different types of geothermal reservoirs. Investigations of idealized systems include effects of gravity and fluid injection. Pressure decline is analyzed as a function of cumulative production. The main conclusions are as follows.
The well-known p/Z method for estimating fluid reserves is not applicable to two-phase geothermal reservoirs. There is a strong tendency toward spatially uniform boiling. This causes a pressure decline, which allows in many cases estimates of the total reservoir volume and of the total heat content of the reservoir rock. Propagation of a boiling front through a deep water table, as a consequence of fluid production, gives rise to a peculiar pattern of pressure decline. This may allow prediction of the distance of the water table from the producing wells and of the vertical thickness of the water zone, thereby giving important clues to estimating fluid reserves. The pressure effects of injection of colder fluid depend strongly on (one- or two-) phase conditions in the reservoir, injection rate, and absolute permeability. Average pressure actually may decline in two-phase reservoirs rather than increase as a result of injection.
Interwell Tracer Analyses of a Hydraulically Fractured Granitic Geothermal Reservoir
Authors: Tester Jefferson W. , Bivins Robert L. , Potter Robert M. 
Published: December 2007

Abstract
Field experiments with fluorescent dye and radioactive tracers (Br82 and I131) have been employed to characterize a hot, low-matrix-permeability, hydraulically fractured granitic reservoir at depths of 2440 to 2960 m (8,000 to 9,700 ft). Tracer profiles and residence time distributions (RTD's) have been used to estimate sweep efficiencies and fracture volumes and to diagnose normal and pathological flow behavior both in injection and in production wells. The effectiveness of one- and two-dimensional (1- and 2D) theoretical dispersion models using single and multiple porous, fractured zones with velocity- and formation-dependent effects is discussed with respect to actual field data.
Equilibrium Calculations on the Kelly-Snyder Reservoir
Authors: Kennedy Harvey T. , Dardaganian Stephen G. , Clanton John L. 
Published: December 2007

Abstract
This paper presents equilibrium ratios measured on oil and gas samples taken from the Kelly-Snyder field at the reservoir temperature of 128°F. From these data smoothed curves were constructed for the reservoir fluid up to the bubble-point, 1,874 psia. A material balance calculation, based on the use of equilibrium ratios instead of the usual solubility and shrinkage measurements is made on the field and compared to the conventional method.

Determination of Equilibrium Ratios
The equilibrium ratios, or K values were obtained by recombining separator samples of oil and gas taken when the reservoir was above its bubble point, and thus represented the reservoir fluid before any change had occurred due to the evolution of gas. The well sampled had a gas-oil ratio of 617 cu ft of high pressure separator gas per barrel of separator oil, and a bottom-hole temperature of 128°F.
Samples were brought to equilibrium by agitating for 24 hours in a thermostat, maintained at the proper temperature within 0.2 °F, mercury being added when necessary to maintain the pressure constant. Samples of oil and gas were then taken by constant pressure displacement, and analyzed by low temperature fractionation.
Equilibrium ratios were determined at 128°F and 500, 800, 1,000 and 1,400 psig. At the latter pressure, there were indications that the gas samples were contaminated with small quantities of oil, and only data taken at the first three pressures were included in Fig. 1. This figure has been extended to higher and lower pressures by the use of the Fluor charts for 3,000 psi convergence pressure, on which the experimental points fit well.

Material Balance Equations
The possible errors involved in conventional material balance equations have been analyzed by Muskat. Where the errors occur in field measurements, or in obtaining effective averages from variables such as gas-oil ratio and pressure, they will evidently be involved in any attempt to estimate the content of the reservoir.
Effects of Friction on Hydraulic Fracture Growth Near Unbonded Interfaces in Rocks
Authors: Anderson Gordon D. 
Published: December 2007

Abstract
Small-scale laboratory experiments were performed to study the growth of hydraulically driven fractures in the vicinity of an unbonded interface in rocks. The purpose was to evaluate under which conditions the hydraulic fractures would cross the interface. The materials used in these studies were Nugget sandstone from Utah (3 to 6% porosity) and Indiana limestone (12 to 15% porosity). The fracturing fluid was oil (viscosity ~ 300 cp) injected into the rock through high-pressure steel tubing. Prismatic blocks of the rock materials to be studied were held adjacent to one another in a hydraulic press so that a normal stress was set up across their mutual interface. Lubricants and surface roughening were used to vary the frictional properties of the interfaces. It was found that as the interface surface friction coefficient was decreased, the normal stress had to be increased for a hydraulic fracture to cross the interface. The frictional shear stress that the interface can support without slippage appears to be critical in determining fracture growth across the interface. Additional experiments were performed to evaluate the coefficient of friction for the different interface surface preparations used. These experiments demonstrated that a variation in the frictional properties along an interfacial surface in the vicinity of hydraulic fracture growth can alter the path of the fracture. The experiments also demonstrated that cracks, which intersect the interface from the side opposite the approaching hydraulic fracture, can impede fracture growth across the interface.