bluuebunny/crossref_metadata_2025_split huggingface dataset:
Kinetics of the Secondary Reaction of HF on Alumino-Silicates
Authors: Gdanski R. D. 
Published: December 2007

SummaryThe standard description of HF acidizing chemistry clearly demonstrates a primary and secondary reaction of HF with alumino-silicates.1–7 Field experience has taught us that possible precipitation during the secondary reaction can adversely affect treatment success,8 especially in formations with high K-feldspar content or temperatures above 300°F. Recent work has also reported the existence of a tertiary reaction of HF with alumino-silicates.9This paper reports the determination of the rate law for the secondary reaction and the kinetics for that reaction on kaolinite and feldspar over a broad temperature range. In addition, the kinetics of fluosilicate precipitation during the secondary reaction were studied and found to be fast but not instantaneous. These findings were made possible by recently applied experimental techniques including 19F nuclear magnetic resonance spectroscopy,9 fractional pore-volume flow experiments,10 and an accurate knowledge of the HF stoichiometry.11 Laboratory find- ings have been verified based on detailed analysis of flowback samples from field treatments.12The reaction rate for the secondary reaction is much slower on feldspars than on clays. At temperatures below 125°F, the secondary reaction rate is very slow, which makes spent HF susceptible to fluosilicate precipitation if the HF is mixed with brines as it often is for disposal or injection well treatments. The difference in the kinetics between clays and feldspar allows one to design treatments at lower temperatures based on just the clay fraction. At temperatures above 150°F, the average mineralogy, clay mineralogy, and feldspar mineralogy should each be evaluated separately for potential fluosilicate precipitation. The fluid of choice is the one that passes all three conditions.The rate law indicates that the speed of the reaction is independent of HCl concentration and would proceed to completion even in the absence of HCl. Chemically, one can accomplish this effect by using water as a proton source and by adjusting the stoichiometry based on a previously reported equilibrium.11 The kinetics for fluosilicate precipitation were fast, but not instantaneous. At very high temperatures, the secondary reaction is fast enough that fluosilicate precipitations can largely be avoided. Unfortunately, the silica gel precipitation then occurs so close to the wellbore that damage to permeability will likely occur. The equations recently developed for the HF acidizing process have been incorporated into a fully kinetic geochemical radial flow simulator. Calculations performed with this simulator have confirmed that a good knowledge of the formation mineralogy and acidizing kinetics is necessary for proper optimization of HF acidizing treatments.
Integrating Dynamic Data Into High-Resolution Reservoir Models Using Streamline-Based Analytic Sensitivity Coefficients
Authors: Vasco D. W. , Yoon Seongsik , Datta-Gupta Akhil 
Published: December 2007

SummaryOne of the outstanding challenges in reservoir characterization is to build high-resolution reservoir models that satisfy static as well as dynamic data. However, integration of dynamic data typically requires the solution of an inverse problem that can be computationally intensive and becomes practically infeasible for fine-scale reservoir models. A critical issue here is computation of sensitivity coefficients, the derivatives of dynamic production history with respect to model parameters such as permeability and porosity.We propose a new analytic technique that has several advantages over existing approaches. First, the method utilizes an extremely efficient three-dimensional multiphase streamline simulator as a forward model. Second, the parameter sensitivities are formulated in terms of one-dimensional integrals of analytic functions along the streamlines. Thus, the computation of sensitivities for all model parameters requires only a single simulation run to construct the velocity field and generate the streamlines. The integration of dynamic data is then performed using a two-step iterative inversion that involves (i) "lining up" the breakthrough times at the producing wells and then (ii) matching the production history. Our approach follows from an analogy between streamlines and ray tracing in seismology. The inverse method is analogous to seismic waveform inversion and thus, allows us to utilize efficient methods from geophysical imaging.We have applied the proposed approach to a highly heterogeneous carbonate reservoir in west Texas. The reservoir model consists of 50,000 cells and includes multiple patterns with 42 wells. Water-cut histories from 27 producing wells are utilized to characterize porosity and permeability distribution in the reservoir, a total of 100,000 parameters.
Visualization and Measurement of Gas Evolution and Flow of Heavy and Light Oil in Porous Media
Authors: Firoozabadi Abbas , Aronson Andrew 
Published: December 2007

Summary
In a number of experiments, the efficiency of solution-gas drive for both light and heavy oils was studied. In these experiments a special coreholder was used to visually observe the formation of gas bubbles on the rock surface of a Berea core and the production from the core outlet. The results from all the experiments reveal that the critical gas saturation for three hydrocarbon liquids; 1. a light model oil, 2. an 11-API gravity oil, and 3. a 35-API gravity oil, does not exceed 3%. However, the gas mobility for the heavy oil is very low and for the light model oil very high. Consequently, solution-gas drive for a heavy oil of 11-API gravity is more efficient than for a light oil.
A Fast 3D Interface Simulator for Steamdrives
Authors: Godderij R. R. , Bruining Johannes , Molenaar J. 
Published: December 2007

Summary
Here we describe a fast 3D steam drive simulator. We use an interface model, where the single-phase steam zone is separated from the two-phase liquid zone by the steam condensation front (SCF) which constitutes the interface. Steady-state heat balances applied at the interface reduce the steam problem to a problem of gas/oil/water flow. Heat losses are treated by a prescribed conversion of steam to water. The model incorporates gravity, viscous and capillary forces and handles arbitrary permeability distributions and well configurations.
We use a multigrid method to solve the pressure equation. The steam zone development is determined by a probabilistic method, which ensures that instability phenomena are properly treated. The oil/water flow problem in the liquid domain is solved as in conventional reservoir simulators. We validate the model with analytical models.
Example calculations for a thin medium-viscosity oil field show that a transition zone with a reduced oil viscosity just downstream of the SCF has a pronounced stabilizing effect. This, and the global heat loss effects are the reason for the high displacement efficiency of steam drives.
Foam Generation at Layer Boundaries in Porous Media
Authors: Rossen W. R. 
Published: December 2007

SummaryFoam can be created by snap-off in a strongly water-wet porous medium as gas and surfactant solution flow across a sharp transition in permeability. A simple pore-network model shows that this depends on a large viscosity contrast between gas and liquid and the ratio of gas and liquid flow rates, but not on the ratio of pore-throat to pore-body diameters. The model explains a variety of experimental observations.
Effect of Wettability on Oil Recovery by Near-Miscible Gas Injection
Authors: Wylie Philip L. , Mohanty Kishore K. 
Published: December 2007

Summary
Oil can become bypassed during gas injection as a result of gravitational, viscous, and heterogeneity effects. Mass transfer from the bypassed region to the flowing gas is dependent upon pressure-driven, gravity-driven, and capillary-driven crossflows as well as diffusion and dispersion. The focus of this study is on the influence that wettability has on bypassing and mass transfer. Experimental results reveal comparatively less bypassing occurs in a strongly oil-wet sandstone than in a water-wet sandstone for gravity-dominated, secondary gasfloods. Mass transfer under oil-wet conditions is enhanced, as a result of oil-wetting film connectivity, over that of water-wet conditions, where water shielding is significant.
Perforating Requirements for Fracture Stimulations
Authors: Behrmann L. A. , Nolte K. G. 
Published: December 2007

Summary
Perforating provides the means of communication between the wellbore and the reservoir, and in a fracture-stimulated reservoir, the perforation is the fluid conduit between the fracture and the wellbore. The existence of, or lack of, a hydraulic microannulus critically affects the choice of perforating parameters. The existence of a microannulus is dependent on reservoir and wellbore properties, perforating parameters, and fracture stimulation execution.
Recommendations are provided to choose the best perforating parameters of: shot phasing, shot density, type of charge interval length and gun orientation. Recommendations are provided for hard and soft rock hydraulic fracturing and extreme overbalance stimulation.
Use of Carbon Dioxide for Water Injectivity Improvement
Authors: Ramsay H.J. , Small F.R. 
Published: December 2007

Abstract
Carbon dioxide (in most cases in the form of carbonated water) has been field proven as an effective agent for increasing water injection rates. Over 300 wells have been treated. In many of the injection wells, substantial water injectivity increases (several fold) have been realized. Various methods of treatments have been applied, but usually the treating materials consist of carbon dioxide, water, a non-ionic surfactant and LPG. Theory of application is briefly presented, along with the role played by the various materials. Methods of application broadly consist of
- injection of highly carbonated water, or
- injection of low level carbonated water or
- injection of slugs of carbon dioxide.
Combinations of these methods have also been used. Field results of the various methods of application are presented.
Introduction
Carbon dioxide has been utilized for some time in secondary recovery operations. One benefit of this utilization is increased water injectivity. However, until about 1 1/2 years ago, field experience with this agent was limited to the injection of fully carbonated water containing small concentrations of a non-ionic surfactant and limited amounts of LPG. At that time, it was decided to explore other methods of obtaining increased water injectivity with carbon dioxide. Also, it was deemed desirable to include a number of oil producing formations. Table 1 shows various formations treated with carbon dioxide. Almost 200 wells had been treated prior to 1962, utilizing three methods of application (listed in Table 1). However, this experience was largely limited to full carbonation treatments in only three formations, with about 80 per cent of these treatments in the Bartlesville sand. Since that time, water injectivity experience with carbon dioxide has been broadened to include 17 more formations. One hundred and thirty-four additional wells have been treated by all three modes of treatment during the past 1 1/2 years. Experience gained from these various treatments has been invaluable. It is the purpose of this paper to discuss briefly the methods and theory of application, to show field case histories of these methods of application and to present conclusions drawn from this range of experience.
Methods of Application
Various methods of application have been used in the field to obtain increased water injectivity. In the majority of the injection wells treated with carbon dioxide, carbonated water has been injected at a solution strength of 70 to 100 per cent of the total saturation at bottom-hole conditions. This method of application is referred to as "full carbonation".More recently, a series of field experiments has been conducted in which the water has been carbonated at a level of about 3 to 4 lb of CO2/bbl of water (26 to 35 scf/bbl).
JPT
P. 25^
Steady Flow Equations for Wells in Partial Water-Drive Reservoirs
Authors: Kumar Anil 
Published: December 2007

This paper presents steady-state radial flow and pressure distribution equations for wells under partial water drive or fluid injection. A parameter f is introduced to characterize the strength of water drive or fluid injection and to show its influence on well productivity.

Introduction
No convenient method exists in petroleum literature to establish the well producing rate and pressure-distribution behavior for wells in partial water drive reservoirs and in fluid injection projects under steady conditions. Such behavior is understood for wells in closed or depletiontype circular reservoirs and in reservoirs with constant pressure at the outer boundary. The latter situation is encountered in an active water drive reservoir or in fully developed five-spot injection patterns. For most wells, a realistic condition at the reservoir drainage boundary is one of partial flow because of limited aquifer or fluid injection in the aquifer or both.
Brownscombe and Collins presented a producing rate equation for a well at steady flow in a closed reservoir. The corresponding flow equation for constant pressure is well known. The derivation of those equations is presented by Craft and Hawkins. Dietz suggested a method presented by Craft and Hawkins. Dietz suggested a method of incorporating the effect of partial water drive on drainage area mean pressure of a well by changing shape factor values.
Steady radial flow equations for a well in a circular partial water drive reservoir are developed in the partial water drive reservoir are developed in the following discussion.

Theory
Consider a well producing at a constant rate from a circular oil reservoir. The formation is assumed to be uniform in thickness, porosity, and permeability. The fluid has a constant viscosity and compressibility at reservoir temperature.
After the initial transients have died down, a well reaches steady flow conditions, where the time rate of change of pressure, dp/dt, is constant with time. It is normally termed pseudosteady or quasisteady state for nonzero values of this constant and "true" steady state when the constant is zero. Under true steady state, pressure at a point acquires a constant value with respect to pressure at a point acquires a constant value with respect to time. Under pseudosteady conditions the absolute value of pressure at a point is changing with time, but the time rate of change of pressure is constant.
Let us consider the flow rate across a radius r under the influence of the following conditions at the outer reservoir boundary at r :
1. No-Flow at r : In a closed or depletion-type reservoir, there is no flow across the outer reservoir boundary, implying that the pressure gradient (dp/dr) at r is zero. The fluid volume at the well (q) is produced solely by expansion of fluid in a cylindrical shell between the radii r and r . In other words: (1)
(2)
as rw less than less than re. The term [pi r h phi c (dp/dt)] represents the expansibility of the fluid contained between the radii re and rw .
JPT
P. 1654
The Planning and Drilling of a Wildcat Well in the Republic of Seychelles by an Operator/Contractor/ Integrated Services Alliance
Authors: Marshall D. W. , Heenan D. H. , Reynolds J. T. 
Published: December 2007

Summary
Constant Bank-1 is a 3,200 m (10,500 ft) wildcat well located in 50 m (164 ft) of water on a carbonate bank in the Republic of Seychelles, a group of tropical islands in the Indian Ocean. In this article we describe the development of a contracting philosophy for planning and executing the project through the formation of an alliance comprised of operator, drilling contractor, and integrated services company. We examine the unique environmental and logistical features of this project and describe how the alliance addressed these critical issues by using the strengths of the respective companies to reduce risks and ensure a cost-effective, successful operation. The logistical management of this rank wildcat well, which was situated in a remote location offering no practical means of resupply and no local resources, was further complicated by the technical difficulties associated with the well.
We conclude by discussing the different objectives of each company in conjunction with the overall project objectives and describing how these respective goals were aligned to the mutual needs of the alliance. The lessons learned by the alliance members are noted and recommendations are made for approaching similar operations.
Comment on Interference Analysis for Anisotropic Formations
Authors: Matthews T.A. 
Published: December 2007

Ramey's paper. "Interference Analysis for Anisotropic Formations - A Case History." (Oct. 1975 JPT. Pages 1290–1298)' is excellent and should form the basis for calculations for years to come.There is an interesting point on nonunique solutions that-should be made. Ramey states that "If C were known. data from only two wells arc sufficient. "His previous remarks indicate that multiple solutions are previous remarks indicate that multiple solutions are possible if both observation wells are on the same straight possible if both observation wells are on the same straight line with the injection well.What is not so obvious. however. is that two solutions are possible in the general case when data from two observation wells are used.Consider the case in which the lines containing the wells are at right angles to each other. Then there is a second solution with the same kxx and kyy as the first, but with the angle 0 being the negative of the first. Inspection of Figs. 1 and 2. and consideration of the fact that Points 1.D and 5-E are independent observation points. makes this clear.Ramey's calculation procedure gives just one answer unless the coordinate axes are rotated 900, putting Point 1-D at (–475. 0) and Point 5-E at (0. 475). This interchanges the values of kxx and kyy, leaves kry, kxx. and kyy the same. and gives an angle of 28 deg.
P. 1429
Oil Production - A Continuing Challenge
Authors: Suman John R. 
Published: December 2007

Rock Oil
In 1855 "rock oil" (petroleum seepages), which sold for 30 to 40 dollars a barrel, was used for medicinal purposes and widely advertised is "good for man or beast." We are all familiar with Col. Drake's "rock oil test" which was drilled near an "old oil spring" at Titusville, Pa., in 1859. After drilling into hard rock at 36 ft, "Drake's Folly" became the joke of the countryside. After many disappointments, the test struck oil at 69 1/2 ft to open the first oil boom in the United States. Many wells were drilled in Pennsylvania, West Virginia, and New York during the next few years forcing the price of oil down to 10 to 20 cents per barrel.
Transportation and refining facilities as well as markets (mostly for lighting and lubrication), increased steadily during the next 40 years. Consequently, oil prices were generally sufficiently low to encourage new uses for oil, and they were sufficiently high to provide a reasonable profit for the new industry.
The completion of the gusher at Spindletop in 1901 by Capt. Anthony F. Lucas ushered in a new era in production and marketing, with the use of fuel oil being expanded rapidly during the next 10 years. It is significant to note that the initial flow of the Lucas well was 75,000 to 100.000 B/Dequal to 50 per cent of the daily oil production in the United States during 1900. In 1901 Capt. Lucas presented a paper on the Spindletop discovery before the AIME. One of the interesting points in his discussion concerned formation evaluation.

Overproduction
Almost before the excitement of the Spindletop discovery had subsided, overproduction became a pressing problem, During the next 25 years, markets as well as daily oil production increased steadily. The ability of the United States to supply the fuel needs for the machines of war during World War I was considered to be an important factor in winning the war. Following World War I, oil production continued to increase. In 1927, E. B. Reeser, president of Barnsdall Oil Co., wrote an article for the Oil and Gas Journal entitled, "A Challenge to the Oil industry." The theme was: "Overproduction must be regulated by cooperation or government supervision. Leaders should develop a plan."
A Theory for Pressure Transient Analysis in Naturally Fractured Reservoirs
Authors: Najurieta Humberto L. 
Published: December 2007

Najurieta, Humberto L.,* SPE, Inst. Mexicano del Petroleo
A method to calculate the unsteady-state pressure behavior within the fractures of a homogeneously fractured reservoir is presented. The technique allows the analysis of pressure buildup and drawdown tests for layer- like and block-shaped fractured reservoirs. The fractures pressure is shown to depend on four parameters, and a method for its pressure is shown to depend on four parameters, and a method for its determination is proposed.

Introduction
The importance of the pressure behavior as a source of information on reservoir characteristics is evidenced by the extensive theoretical work developed in this field. Homogeneous reservoirs can be described theoretically for a great number of boundary and production conditions.The basic theory for the analysis of homogeneous isotropic reservoirs is based on the line-source solution to the radial diffusivity equation:
(1)
The solution is
(2)
Eq. 2 shows that homogeneous isotropic reservoirs can be described using at least two parameters: the reservoir transmissivity T=k h/mu and the reservoir diffusivity eta=k/phi muc. Several techniques are used widely to estimate these parameters; from them, we can calculated two unknowns (e.g., k and phi provided we know the remaining (h, mu, and c). The provided we know the remaining (h, mu, and c). The definition of the skin effect and the use of the superposition principle and image wells widen the practical applications of Eq. 2. practical applications of Eq. 2. Several authors have dealt with nonhomogeneous and nonisotropic reservoirs. The solutions proposed are complex and generally require computer handling.Among the heterogeneities in a reservoir, there is an important one that is due to the presence of natural matrix fractures. In this case the productive pay is fragmented by a spatial fracture network as a pay is fragmented by a spatial fracture network as a result of the natural geologic factors. Few authors have suggested theories to aid in calculating the characteristics of naturally fractured reservoirs. A detailed theory, developed by Warren and Root, based on the theoretical work by Barenblatt and Zheltov, assumes a network of orthogonal, equally spaced features. Thus, the reservoir is made up of blocks that are able to exchange fluids with the fractures.Barenblatt and Zheltov suggested that the flow from the matrix could be considered as a first approach in a semisteady-state regime. With this assumption Warren and Root developed the differential equations and obtained analytical solutions for well test analysis. When these solutions are plotted in a conventional way (e.g., a Horner plot), plotted in a conventional way (e.g., a Horner plot), they show two parallel straight lines connected by a transition zone of variable slope. The vertical distance between them is related to the relative storage capacity of the fractures and the slopes with the flow capacity of the reservoir.
JPT
p. 1241