bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fracture Width and Embedment Testing in Soft Reservoir Sandstone
Authors: Lacy L. L. , Rickards A. R. , Bilden D. M. 
Published: December 2007

Summary
A new computer-controlled laboratory technique has been developed to measure propped fracture width and embedment in weakly consolidated cores or unconsolidated sands under simulated downhole conditions. Previously, laboratory studies on cores had determined embedment in hard rocks where embedment was normally limited to 50% of the proppant grain diameter. Several studies also indicated the importance of embedment with one monolayer or less of proppant coverage. The effects of water saturation and fracture-fluid filtrate on formation softness and embedment have not been previously published. Consequently, the objectives of the current paper are to extend previous research results to include soft, weakly consolidated cores and unconsolidated sands with multiple proppant layers. The influence of water saturation and dynamic fluid leakoff on embedment are also shown to be important.
The current investigations indicate that embedment becomes a problem when the Brinell hardness (BH) of the formation is less than about 20 kg/mm2 or when the static Young's modulus of formations cores is less than about 2 million psi (13 GPa). Embedment has been determined for cores with static Young's moduli between 0.1 and 1.4 million psi (0.7 to 9.6 GPa). In soft and wet sandstone, embedment can reduce fracture width up to 60% or more for proppant concentrations of 2 lbm/ft2. For unconsolidated sands, embedment is influenced by fracturing-fluid type, water saturation, and downhole conditions. Cyclic loading conditions associated with well shut-ins also increase embedment in unconsolidated sands. This paper reviews and discusses test data on formation cores from south Texas, New Mexico, the North Sea, and the Gulf of Mexico. Most of the commercial fracture-design programs neglect embedment problems in calculating fracture width, while other fracture simulators contain allowances for embedment.
A Further Note on Pulse-Test Interpretation
Authors: Startzman R.A. 
Published: December 2007

The development of pulse testing, a special type of well interference testing, has resulted in interpretation techniques that require the use of graphical methods. These methods make use of such variables as "time lag" and "pressure response", obtained visually from plots of well pressure vs time. Such methods require that the pulse-rate schedule be a symmetric, rectangular step-function of constant frequency and amplitude.
In actual field practice it may be impossible to maintain a pulse-rate schedule of this type. Furthermore, even if such a schedule could be adhered to, the resulting pressure signal in the responding well might possess a high degree of random noise. Noise caused, perhaps, by a low-resolution pressure instrument can obscure the test results so that time lag and pressure response cannot be determined accurately.
A more general approach that overcomes these difficulties is that of automatically history-matching observed responding well pressures with pressures computed from a mathematical model. A convenient method is to minimize the least-squares objective function
(1)
Any obvious long-term reservoir pressure trends must be removed from the measured pressures in order to arrive at po. An analysis of the residuals, (pt - po), computed at the minimum of psi, will determine if pressure trends have been successfully removed.
Since pt and its first and second derivatives can be determined analytically from the exponential integral solution to the diffusion equation, a useful minimization technique is the Newton-Raphson method. This method is used to solve the following equations for transmissibility, T, and storage, s:
(2)
and
(3)
This interpretation technique was programmed in FORTRAN for the IBM 360/50. The Newton-Raphson method was found to be quite satisfactory and most problems took less than 10 seconds for adequate convergence.
P. 1143ˆ
Field Examples of Ultrasonically Enhanced Density, Neutron-Porosity, and Caliper Logs Obtained While Drilling
Authors: Schultz W. E. , Moake G. L. , Jackson C. E. 
Published: December 2007

SummaryDensity, photoelectric factor (Pe), and neutron-porosity measurements made while drilling are extremely sensitive to the distance between the sensors and the borehole wall (standoff). To minimize these effects, an ultrasonic transducer is positioned collinearly with the nuclear sensors. Rapid pulsing of the transducer provides frequent measurements of the standoff. These measurements are used to average the nuclear data in a manner that emphasizes the smallest standoff data. This greatly improves the quality of the density, Pe, and neutron-porosity logs. Additionally, the standoff measurements are used to correct the neutron log for residual standoff effects. Measurements from the standoff transducer are also combined with those from two other ultrasonic transducers to obtain a high-resolution caliper log. Besides providing useful borehole information, the caliper readings are used to correct the nuclear measurements for hole-size effects. This new technology is illustrated with log examples from a variety of wells. One of the examples illustrates the effectiveness of an enhanced-vertical-resolution processing technique in identifying thin beds.
Estimation of Lithofacies Proportions by Use of Well and Well-Test Data
Authors: Hu L. Y. , Blanc Georges , Noetinger Benoit 
Published: December 2007

SummaryA crucial step of the two commonly used geostatistical methods for modeling heterogeneous reservoirs, sequential indicator simulation and truncated Gaussian simulation, is the estimation of the lithofacies local proportion (or probability density) functions. Well-test-derived permeabilities show good correlation with lithofacies proportions around wells. Integrating well and well-test data in estimating lithofacies proportions could permit the building of more realistic models of reservoir heterogeneity. This integration is difficult, however, because of the different natures and measurement scales of these two types of data.This paper presents a two-step approach to integrating well and well-test data into heterogeneous reservoir modeling. First, we estimate lithofacies proportions in well-test investigation areas with a new kriging algorithm called KISCA. KISCA consists of kriging jointly the proportions of all lithofacies in a well-test investigation area so that the corresponding well-test-derived permeability is respected through a weighted power-averaging of lithofacies permeabilities. For multiple well tests, an iterative process is used in KISCA to account for their interaction. After this, the estimated proportions are combined with lithofacies indicators at wells for estimating proportion (or probability density) functions over the entire reservoir field with a classical kriging method.We considered some numerical examples to test the proposed method for estimating lithofacies proportions. In addition, we generated a synthetic lithofacies reservoir model and performed a well-test simulation. The comparison between the experimental and estimated proportions in the well-test investigation area demonstrates the validity of the proposed method.
Reservoir Fracture Mapping Using Microearthquakes: Two Oilfield Case Studies
Authors: Phillips W. S. , Rutledge J. T. , Fairbanks T. D. , Gardner T. L. , Miller M. E. , Maher B. S. 
Published: December 2007

SummaryPatterns of microearthquakes detected downhole defined fracture orientation and extent in the Austin chalk, Giddings field, Texas, and in the 76 field, Clinton County, Kentucky. At two sites in the Austin chalk we detected more than 480 and 770 microearthquakes, respectively, during hydraulic stimulation, and more than 3,200 during primary production in Clinton County. The data were of high enough quality that 20%, 31%, and 53% of the events could be located, respectively.Reflected-wave data constrained microearthquake locations to the stimulated depths at the base of the Austin chalk. In plan view, microearthquakes defined elongate fracture zones extending from the stimulation wells parallel to the regional fracture trend. However, the widths of the stimulated zones differed by a factor of five between the two Austin chalk sites, suggesting a large difference in the population of ancillary fractures. Post-stimulation production was much higher from the wider zone.In Clinton County, microearthquakes defined low-angle, reverse-fault fracture zones above and below a producing zone. Associations with depleted production intervals indicated that the mapped fractures had been drained previously. Drilling showed that the fractures currently contain brine. The seismic behavior was consistent with stress changes associated with poroelastic effects above and below a drained volume or with the mass exchange of brine replacing produced oil.
Permeability Reduction by Pyrobitumen, Mineralization, and Stress Along Large Natural Fractures in Sandstones at 18,300-ft Depth: Destruction of a Reservoir
Authors: Lorenz J. C. , Billingsley R. L. , Evans L. W. 
Published: December 2007

Summary
Gas production from the Frontier formation at 18,300-ft depth in the Frewen Deep #4 well, eastern Green River basin (Wyoming), was uneconomic despite the presence of three sets of numerous, partially open, vertical natural fractures. Production dropped from 360 Mcf/ D to 140 Mcf/D during a 10-day production test, and the well was abandoned. Examination of the fractures in the core suggests several possible reasons for this poor production. One factor is the presence of mineralization in the fractures. Another more important factor is that the remnant porosity left in the fractures by partial mineralization is commonly plugged with an overmature hydrocarbon residue (pyrobitumen). Reorientation of the in-situ horizontal compressive stress to a trend normal to the main fractures, which now acts to close fracture apertures during reservoir drawdown, is also an important factor.
Re-Engineering Simulation: Managing Complexity and Complexification in Reservoir Projects
Authors: Saleri N. G. 
Published: December 2007

Summary
Managing complexity and technological complexification is a necessity in today's business environment. This paper outlines a method to increase value addition significantly by multidisciplinary reservoir studies. In this context, value addition refers to a positive impact on a business decision. The approach ensures a level of complexification in line both with business questions at hand and the realities of reservoirs.
Sparse well control, seismic uncertainties, imperfect geologic models, time constraints, software viruses, and computing hardware limitations represent some common reservoir realities. The process model detailed in the paper uses these apparent shortcomings to moderate (i.e., guide) the level of complexification. Several project examples illustrate the implementation of the process model. The paper is an extension of three previous investigations1–3 that deal with issues of method and uncertainty in reservoir-performance forecasting.
Gas Hydrates of Hydrogen Sulfide-Methane Mixtures
Authors: Noaker Leslie J. , Katz Donald L. 
Published: December 2007

Abstract
Experimental data are presented for hydrate formation conditions for mixtures of hydrogen sulfide and methane. Vapor-solid equilibrium constants for hydrogen sulfide are also presented. Equilibrium constants, defined here as the ratio of the mole fraction of hydrogen sulfide in the vapor phase (dry basis) to the mole fraction of hydrogen sulfide in the solid phase (dry basis), were calculated using the vapor-solid equilibrium constants for methane presented in an earlier paper. The conditions at which a natural gas will form gas hydrates with water may be computed from its composition, when hydrogen sulfide is present in addition to carbon dioxide and the paraffin hydrocarbons.

Introduction
Many gases are known to form solid hydrates in the presence of liquid water at temperatures above 32°F. This hydrate formation is of importance to the natural gas industry inasmuch as most of the constituents found in natural gases will form hydrates. The attention of the industry was called to hydrates by Hammerschmidt in 1934. A number of papers have been written giving the temperatures and pressures at which these hydrates will form and a bibliography on the subject has been compiled. Deaton and Frost report work for various pure gases and for some natural gases. Katz and co-workers have reported data for various gases at high pressure. They developed a method of predicting conditions for hydrate formation from equilibrium constants and from gas gravity. The effects of anti-freeze agents on the formation of hydrogen sulfide hydrate were reported by Bond and Nelson. The hydrogen sulfide-water system, including hydrate, has been the subject of recent investigation by Sage and co-workers.
Mixtures of hydrates behave as solid solutions and an equilibrium exists between the vapor phase and the solid phase that appears to be comparable to the equilibrium between vapor and liquid phases. By means of the vapor-solid equilibrium constants which have been published for methane, ethane, propane, isobutane, and carbon dioxide it is possible to determine the temperature and pressure at which hydrates will form for a specific gas mixture when water is present.
Effective Transmissibilities of a Gridblock by Upscaling — Comparison of Direct Methods with Renormalization
Authors: Peaceman Donald W. 
Published: December 2007

SummaryPrevious methods for upscaling fine-scale permeability data for use in reservoir simulation produce effective permeabilities for each simulator gridblock. Since transmissibilities between neighboring gridblocks are required by the simulator, it is better to determine six "half-block transmissibilities" for each gridblock. These can be calculated directly by solving the finite-difference equations for pressure in each of six half-blocks, wherein uniform pressures are applied at two opposite faces and no-flow conditions are applied at the other four faces.Alternatively, in order to reduce computation time, renormalization has been proposed for calculating effective permeabilities of the gridblocks. These previous proposals ignore anisotropy and require that the elemental blocks and each coarse block be rectangular. In this paper, renormalization is modified to avoid these disadvantages.Renormalization is most easily implemented if there are N × N × N elemental blocks within each coarse block, where N is a power of 2. A more flexible variation of renormalization is also presented which reduces this restriction somewhat. However, the direct method is much more flexible with regard to the number of elemental blocks in each direction.While renormalization might be expected to be faster than the direct method, comparison of running times shows that a highly efficient iterative solver for the direct method is somewhat faster than renormalization.
Thermodynamic Micellization Model for Asphaltene Aggregation and Precipitation in Petroleum Fluids
Authors: Pan Huanquan , Firoozabadi Abbas 
Published: December 2007

Summary
A thermodynamic framework is proposed to describe the structure of asphaltene micelles and precipitation in crude. The asphaltene micelle is assumed to consist of an asphaltene core surrounded by a solvated shell. The shell contains both resin and all the other species except asphaltenes. The theoretical framework consists of the standard Gibbs free energy of micellar formation and the Gibbs free energies ofthe petroleum liquid and the precipitated phase. The standard Gibbs free energy of the micellar formation is modeled as the sum of various contributions including the association between asphaltene molecules in the core, the deformation of asphaltene and resin molecules in the micelle, and the adsorption of resin molecules onto the micellar core. The Gibbs free energy ofthe petroleum liquid phase includes the contributions from the standard state, mixing, and interactions among the species. The precipitated phase is assumed to be an ideal solid mixture of asphaltenes and resin.
The direct minimization of the Gibbs free energy of the liquid/solid system is invoked to calculate the micellar structure and composition in crude and the amount and composition of the precipitated phase. The predicted results reveal that the addition of diluents n-C5 to n-C10 leads to asphaltene precipitation; whereas diluents such as C2 or C3 give rise to precipitation of nearly all resin and asphaltenes from crude. These predictions are in agreement with laboratory measurements. The predicted micellar size increases with dilution ratio. This prediction is also in agreement with measured data.
Material Balance for a Bottom-Water-Drive Gas Reservoir
Authors: Dumore J.M. 
Published: December 2007

Abstract
A material balance is developed for a gas reservoir in which the rising gas/water contact remains horizontal. The time-integrated cumulative water influx is introduced, which for numerical computations is sometimes more advantageous than the van Everdingen and Hurst integral. On the basis of the equations developed, material balance calculations of the history of an actual gas field are carried out to calculate the water influx. The strength of the estimated radial, limited aquifer, which must supply the water for the influx, is determined. It appears that the strength decreases with time and asymptotically approaches a limiting value. (Some possible reasons for this decrease are mentioned.) If we take the strength as constant and equal to the limiting value, however, very small deviations from the past pressures occur. With the same value for the strength of the aquifer, the future behavior of the gas reservoir is computed, assuming constant gas production rate and no water production.

Introduction
For a depletion-type gas reservoir - i.e., when there is no water encroachment - the average gas pressure is a function of the cumulative production pressure is a function of the cumulative production and can easily be calculated from a material balance. For a gas reservoir bounded by an aquifer, the average gas pressure also depends on the water influx, which in turn depends on the rate of pressure decline and thus on the production rate. In this case the material balance is much more complicated. In the following we have developed the material balance of a bottom-water-drive gas reservoir, in which the rising gas/water contact remains horizontal. In a numerical example, the equations are applied to an actual gas field in Northwest Germany.
A Modified Two-Phase Well-Control Model and Its Computer Applications as a Training and Educational Tool
Authors: Choe Jonggeun , Juvkam-Wold Hans C. 
Published: December 2007

Summary
This paper presents a modified two-phase well-control model to simulate two-phase kick behavior after comparing a dynamic two- phase well-control model and a single-phase model. The model is reliable and easy to simulate without any of the numerical problems that might occur in a dynamic two-phase model. The simulator calculates gas influx rate from the formation assuming an infinite-acting reservoir.
The paper also introduces computer applications for IBM-compatible personal computers for use as a well-control training and educational tool. The simulator has enhanced graphical presentations with random access for all menus and options by use of a computer mouse. The simulator is written in Visual Basic™3.
The simulator can handle vertical wells, directional wells, extended-reach wells, and horizontal wells with two different buildup rates for onshore or offshore wells. The simulator also provides the theoretical kill sheet for any selected well geometry. The simulator is a user-interactive well-control program with an automatic wellcontrol option. It demonstrates the basic concepts of well control and shows the pressure and volume responses of the kick with time.
Complex Multiphase Equilibrium Calculations by Direct Minimization of Gibbs Free Energy by Use of Simulated Annealing
Authors: Pan Huanquan , Firoozabadi Abbas 
Published: December 2007

Summary
The computational problems in reservoir fluid systems are mainly in the critical region and in liquid-liquid (LL), vapor-liquid-liquid (VLL), and higher-phase equilibria. The conventional methods to perform phase-equilibrium calculations with the equality of chemical potentials cannot guarantee a correct solution.
In this study, we propose a simple method to calculate the equilibrium state by direct minimization of the Gibbs free energy of the system at constant temperature and pressure. We use the simulated annealing (SA) algorithm to perform the global minimization. Estimates of key parameters of the SA algorithm are also made for phase-behavior calculations. Several examples, including (1) VL equilibria in the critical region, (2) VLL equilibria for reservoir fluid systems, (3) VLL equilibria for an H2S-containing mixture, and (4) VL-multisolid equilibria for reservoir fluids, show the reliability of the method.
A Low-Tension Waterflooding Process
Authors: Foster W.R. 
Published: December 2007

A field test to examine some aspects of surfactant behavior, and a later polymer injection study, led to the conclusion that a tertiary oil bank can polymer injection study, led to the conclusion that a tertiary oil bank can be formed in a reservoir using low-tension surfactants. Another conclusion is that it is essential to control the mobility immediately behind the bank to insure that a significant fraction of the mobilized oil will be driven to the producing wells.

Introduction
The work summarized here represents a part of the effort by Mobil Research and Development Corp. to develop an economic low-tension waterflooding process. Various aspects of displacement at low tension process. Various aspects of displacement at low tension are discussed in general terms. Details of the extensive background effort supporting the necessary laboratory and field experiments, an interpretation of results, and the development of an adequate transport theory are deferred to later publications. Not all aspects of this process have been field tested yet. However, Mobil has carried out a field test in South Texas to examine factors relating primarily to surfactant behavior. A polymer injection study was conducted at the same site some time later. As a result of these field studies and supporting theory we conducted that a tertiary oil bank can be fanned in a reservoir using low-tension surfactants and that mobility control immediately behind the bank is essential to insure that a significant fraction of the "mobilized oil" will be driven to producing wells. A surfactant waterflooding process capable of producing a tertiary oil bank has also been described by producing a tertiary oil bank has also been described by Gogarty and Tosch. One significant difference between their "Maraflood" process and the process described here is the manner in which the surfactant is used. Maraflood employs a surfactant slug that is miscible with the reservoir crude. Miscibility implies zero interfacial tension between this slug and the reservoir crude oil. Achieving and, particularly, maintaining this miscibility condition places rigorous requirements on the composition of the slug. Our process, on the other hand, does not depend upon process, on the other hand, does not depend upon miscibility between crude oil and water, but relies on very low interfacial tension between a water solution/ dispersion of a surfactant and the reservoir crude oil. Also, the compositional requirements that must be met in order to achieve and maintain a condition of very low tension are somewhat different from those needed in the Maraflood process.