bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Investigation of Oil Destabilization of Nitrogen Foams in Porous Media
Authors: Raterman K. T. 
Published: December 2007

Abstract
When applied as conformance treatments, foams are required to effectively reduce gas injectivities over prolonged periods of time. Frequently, this ability must be manifested in the presence of a residual oil saturation which often exerts a destabilizing effect on foam and the capacity to generate foam.
In this study, the capacity to generate and sustain foam in the presence of a residual oil saturation was examined by each of two methods. The first method monitored the in-situ generation of nitrogen foam at constant pressure drop for 1-ft Berea cbres at a residual oil saturation to surfactant. Gas mobility reduction, foam longevity, and the rate of foam decay were quantified for a variety of surfactants and oils at constant salinity and concentration at room temperature. The second procedure involved the constant quality injection of pregenerated foams into Berea cores at residual oil saturation to water flooding. The liquid requirement to reach steady state and the absolute pressure drop were determined under test conditions identical to the aforementioned method. In each method, foam stability showed a strong sensitivity to surfactant, oil type, in-situ foam quality and oil desaturation kinetics.
In a companion laboratory study, the degree of correlation between these results and a variety of benchtop measurements was established. Benchtop measurements included interfacial and surface tensions, film elasticities, oil spreading, pseudoemulsion film drainage times, and film disjoining pressure for oil equilibrated and nonequilibrated surfactant solutions.
From these studies, it is concluded that foam destabilization by oil is dictated primarily by pseudoemulsion film stability. The relative stability of the pseudoemulsion films in-situ, however, is dependent upon the prevailing pore level conditions of oil and liquid saturation. Oil spreading, wave dampening, and lamellar film strength had little effect on foam stability to oil. Given this information, one can easily choose test design criteria upon which to screen surfactants for foam conformance treatments in the presence of oil.
Developments in Oil Shale
Authors: Pownall John R. 
Published: December 2007

It is generally agreed that the world's energy needs are now doubling every 20 years. Within 10 to 15 years, this rate of increase should create a wide enough gap between crude oil supply and demand to enable other sources of energy to enter our economy on a competitive basis. Without question, new energy sources, such as nuclear, will fill a good portion of this gap. However, there should be a sufficient increase in demand for liquid fuels in the transportation field (vehicles, airplanes, trains), to provide new opportunities for the fossil fuels (coal, tar sands and oil shale)
As a part of this program, I have been asked to sum up the situation in regard to the development of oil shale as a contender in the race to supply synthetic fuels. One of the world's richest deposits of oil shale occurs in the Green River Formation, as shown in the attached Figure 1, in the tri-state area where Colorado, Utah and Wyoming meet. The Green River Formation encompasses an area of 16,500 square miles and contains the world's single, largest hydrocarbon deposit with 1 1/2 trillion barrels of known reserves.
Fluid Effects in Temperature Observation Wells
Authors: Griston S. 
Published: December 2007

ABSTRACT
Temperature profile data are important in the evaluation of steamflood performance. Observation well temperature profiles are used to determine areal sweep, rate of advance of the heat front, vertical coverage of the steamflood, and heat losses to overlying and underlying strata. In such cases, it is commonly assumed that temperature profiles obtained from observation wells closely represent the true temperature distribution in the surrounding formation. In reality, however, natural convection of the wellbore fluids, heat conduction along the tubing, and probe response time are factors that can alter these profiles. Therefore, these factors must be considered when collecting and evaluating temperature profiles.
This paper presents the results of laboratory and field studies of wellbore fluid effects on temperature profiles. The emphasis of this work is on profile smearing caused by natural convection of the wellbore fluid and by slow probe response. Laboratory tests were conducted in a 20-ft vertical well model to initially compare temperature profiles in water- and air-filled wellbores. Field tests were also conducted to further study smearing effects under actual field conditions. Response times of two electrical temperature probe designs, wall-contact, and hanging were also evaluated in the laboratory and the field.
Regulatory Control of Groundwater Contamination by Hazardous Waste Disposal Wells: An Engineering Perspective
Authors: Kamath K. I. 
Published: December 2007

ABSTRACT
A major cause of ground water pollution by hazardous industrial chemical waste disposal wells is a leaky well casing. The detection of such leaks and prompt action to correct them is an important element of the federal Underground Injection Control (UIC) program for ground water protection. Two methods have been in use for casing leak detection in the conventional well with tubing set in a packer: one based on monitoring the volume (level) of liquid in the annulus; the other on monitoring the pressure ("annulus pressure") of a pressurized gas "cap" artificially imposed over the liquid in the closed well annulus. Obviously, annulus liquid volume monitoring relates casing leaks directly to liquid volume loss, while annulus pressure monitoring equates the same indirectly with the resulting gas pressure decline. However, relating loss in liquid volume to gas cap pressure decline is based on the presumption of isothermal conditions and the absence of gas-liquid interaction within the annulus. As neither condition obtains in the well environment, the reliability of the annulus pressure monitoring method which is now a primary federal requirement appears to be in serious doubt. The need, for a re-evaluation of the regulatory status of annulus pressure monitoring for casing integrity and for a technically sound alternative method is thus apparent.
It is shown that annulus liquid level monitoring is possibly the simplest and most practical method for monitoring casing leaks. Imposition of a pressurized gas cap can enhance the rate of liquid leakage and thereby increase the sensitivity of the monitoring process.
Long-Term Study of Cushion Gas Replacement by Inert Gas
Authors: de Moegen H. , Giouse H. 
Published: December 2007

Abstract
To replace part of the cushion gas in an underground gas storage by inert gas is of significant economic interest. Injection of inert gas before natural gas was performed as many as ten years ago on the aquifer storage of SAINT-CLAIR-SUR-EPTE (FRANCE). Meanwhile several projects involving the substitution of cushion gas already in place have been studied (FRANCE, USA).
Nevertheless, operators still ask important questions concerning the long-term behavior of a storage containing inert gas as a part of its cushion. These questions most often focus on the effect mixing has on the withdrawn-gas quality.
Therefore, theoretical considerations, supported by field experiments on "mutli-gas" storages operated by GdF, are examined.
In addition, a real-case study is shown, primarily because a 20 % substitution of cushion is about to begin in the SAINT-ILLIERS (FRANCE) storage. Towards this end, a two-phase, three-dimensional model was used taking into account all physical phenomena and including a precise description of the heterogeneities.
Results in the real-case are given for a long-term study extending from 1965 to 2015, and include the following: –Color-filled contour and grids plots illustrating inert gas concentrations at different values of time.–Future concentration histories of the operating zone and of the observation wells.
One significant result shows that the gas quality during production periods is predicted as always compatible with the BTU requirements of the storage operation: the maximum inert gas concentration withdrawn is approximately one percent at most.
The general behavior trends of the SAINT-ILLIERS storage can then be extended to other reservoirs containing inert gas as a part of their cushion. A sophisticated study is required, but the change from base gas to inert gas is manageable and produces a reliable gas quality, even for long-term operations.
Multiple Transient Analysis of Drawdown And Buildup Tests with Continuous Variation of Flow Rate
Authors: Seidel H.A. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the Society of Petroleum Engineers of AIME, Regional Secondary Recovery Symposium, to be held in Pampa, Tex., Oct. 26–27, 1967. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
To apply techniques available in the literature for interpretation of individual well drawdown test data for reservoir boundary conditions and performance predictions properly, it is necessary that the pressure data be observed at constant flow rates. This paper presents a method which takes into account the variation of flow rates that are generally observed during most drawdown tests.
In one example cited, the drawdown test analysis b:, conventional methods suggested that connected oil in place would amount to more than 1 million bbl of oil. Actual production history and analysis by the multiple transient method indicates oil in place to have been on the order of 200,000 bbl. This latter technique provides a very useful tool for short-term drawdown reserve determinations, when coupled with the permeability variation of the reservoir, which tends to make calculated short-term drawdown tested reserves conservative or less than actual. In addition, wellbore conditions and formation capacity within the test volume can be more accurately determined for better well performance predictions.
With successful interpretation of pressure drawdown and buildup data, an engineer can save his company substantial investment by preventing unnecessary development, especially in areas of relatively deep, one-or two-reservoir fields. On the other hand, he can provide the necessary information to justify an accelerated development program at minimum risk to improve the present value of an undeveloped property.

METHOD OF ANALYSIS
The multiple-transient equation for continuous succession of steady states can be set up for simultaneous solution of several pressure-time relationships which can be measured at the well.[1]
for oil flow. The pw and pi terms are squared for gas flow.
[2]
A Discussion of Calicum Carbonate Scaling Problems and Solutions With Respect to Produced Brines
Authors: Oddo J. E. , Tomson M. B. 
Published: December 2007

ABSTRACT
Seven barrels of oilfield brine are produced for every barrel-equivalent of energy obtained in the United States each year. With enhanced recovery of hydrocarbons this ratio can be as high as thirty or fifty to one. Scale deposited within production systems associated with high volumes of produced brine can pose serious problems to the operator. Controlling scale affects the economics of the field and a scale problem left untreated can result in the total loss of production or costly replacement of facilities.
Predicting potential scaling problems can be difficult and numerous saturation indexes have been developed to assist in this regard. Some of these will be compared and contrasted along with the advantages and disadvantages of mainframe computer codes. Methods to inhibit scale formation can be varied and are vastly different with respect to economic impact and result.
These possible methods including acidization, sequestration, dilution, pressure and temperature control, induced precipitation and inhibitor treatment by treat string and squeeze into the formation will be discused. Finally, the history of scale control in co-production gas wells will be presented. The discussion will focus on inhibitor treat string design and effectiveness and the planning and results of an inhibitor squeeze project.
On the Determination of the Pressure-Dependent Characteristics of a Reservoir Through Transient Pressure Testing
Authors: Samaniego F. , Cinco-Ley H. 
Published: December 2007

ABSTRACT
A practical procedure is presented to determine the pressure dependent characteristics of a reservoir from transient pressure analysis. These characteristics are expressed in terms of k(p)/{1−ϕ(p)} or if porosity is considered constant in terms of permeability. Expressions are derived for flow in stress sensitive formations of pressure dependent liquid flow and of real gas flow, that allow through the analysis of drawdown or buildup tests, for liquid flow and the analysis of these tests and multiple-rate tests for gas wells, the determination of the stress sensitive characteristics of the producing formation. The best way to obtain the stress sensitive characteristics of the reservoir is to carry out a drawdown test at a high rate, that results in an important pressure decrement, allowing the estimation of the pressure dependent formation parameter in a wide range of pressure. In an alternate manner, the stress sensitive characteristics can be estimated through the analysis of a buildup test preceded by a production period at a high rate. Further improvement may be attained when a combination of both tests, a drawdown and a buildup test is used. It is also demonstrated that to circumvent the problem of estimation of the pressure dependent parameter at early times during the test, due to the influence of wellbore storage and wellbore damage, the "convolution" methods of analisys that make use of both the sandface flow rate and the bottom -hole pressure can be used. The proposed method is tested through the analysis of simulated tests, with errors in estimated results of k(p)/{1− ϕ(p)} or formation permeability of less than 5 percent. Also a discussion of an extension of the Agarwal's pseudo-time concept for pressure dependent liquid flow in a stress sensitive formation is presented.
Pressure Transient Analysis of Injection Wells in Reservoirs With Multiple Fluid Banks
Authors: Yen N-S. , Agarwal R. G. 
Published: December 2007

ABSTRACT
This paper presents a newly developed pressure transient analysis method for analyzing the injection well test pressure data from a well-reservoir system with multiple fluid banks. This new method should enable engineers to calculate the mobility profile in the reservoir, fluid bank radii during the falloff period and the pressure distribution in the reservoir at the instant of shutin. The utility and application of the new analysis procedure have been discussed and demonstrated by means of simulated cases and field examples.
Identifying and Estimating Desorption From Devonian Shale Gas Production Data
Authors: Lane H. S. , Watson A. T. , Lancaster D. E. 
Published: December 2007

ABSTRACT
A methodology for identifying and estimating desorption from Devonian shale gas production data is presented. The methodology can be used regardless of whether independent information about the existence of adsorbed gas is available. Several example cases are presented which indicate that, in certain situations, the presence of the desorption mechanism can be detected from a history match of production data.
The accuracy of the parameter estimates used to describe the desorption process is also examined. Results indicate that the desorption parameters cannot be estimated accurately from production data; however, production forecasts based on history matches that include the effects of desorption are found to be more accurate than when desorption is not taken into account.
Boundary Effects in Pressure-Transient Data From Layered Reservoirs
Authors: Larsen Leif 
Published: December 2007

SUMMARY
A detailed investigation is presented of boundary effects in pressure-transient data from layered reservoirs with or without crossflow. The main contribution of the paper is a method to generate exact Laplace-transformed solutions with effects of a great variety of boundary configurations included. These solutions can in turn be used to generate synthetic data for use in interactive or automated history-matching analyses. Real-space limiting forms of some of the simpler solutions are also presented, and these can be used to interpret observed behavior in terms of conventional analyses of distance to boundaries and radius of investigation.
The boundary configurations that can be treated by the methods in the paper cover, in addition to the familiar circular and unbounded cases, all those that can be generated by image-well techniques in single-layer reservoirs. For zones made up of neighboring layers with crossflow the boundaries must be common to all layers (fully penetrating). Between layers without crossflow there are no such restrictions.
Type Curve Development and Applications for Predicting Production Performance of Horizontal Wells in Low Permeability Gas Reservoirs
Authors: Aminian K. , Duda J. R. , Amerl S. 
Published: December 2007

ABSTRACT
Horizontal wells can be effective alternatives to fractured vertical wells in low permeability reservoirs by increasing economically recoverable gas. Given this potential, simple but reliable methods for determining the production performance of horizontal wells must be available. To aid in these forecasts, production type curves were developed. These curves can be used to predict the production of horizontal wells during preliminary evaluations, thus avoiding the need for costly and time consuming computer simulations. The effects of vertical-to-horizontal permeability, and the ratio of the horizontal well length to the length of the reservoir are also discussed. Application of the curves is illustrated using pre-stimulation production data from a horizontal well drilled into a tight gas-bearing formation. Forecasted gas production using the type curves closely matches the field data and demonstrates their utility.
Predicting Retrograde Phenomena and Miscibility Using Equation of State
Authors: Mansoori G. A. , Savidge J. L. 
Published: December 2007

ABSTRACT
While the knowledge about the retrograde condensation and condensing-gas drive phenomena is not new their utilization in production-stimulation and simulation of the natural gas and NGL reservoirs has been delayed due to the lack of accurate predictive computer algorithms. In this report the groundwork for accurate computation and prediction of the behavior of reservoir fluids under retrograde condensation and in condensing-gas-drive conditions are presented. It is shown that through equations of state one can predict the following properties of the reservoir fluid systems: The minimum miscibility conditions and solubilities of intermediate and heavy hydrocarbons in miscible solvents.The effect of mixed miscible solvents and entrainers on lowering the minimum miscibility pressure of heavy components of reservoir fluids.The role of variations in temperature, pressure, and solvent composition on the miscibility and solubilitiies.Flash (dew point and bubble point) calculation for complex reservoir fluids in VLE and VLLE cases.
Use and Misuse of the Superposition Time Function in Well Test Analysis
Authors: Cinco-Ley H. , Samaniego V. F. 
Published: December 2007

ABSTRACT
The superposition time function has been used as a tool to analyze transient pres sure data measured under the influence of a variable flow rate. This function is usually defined assuming that radial flow equations are valid, however, in practice there are cases that exhibit several flow regimes (i.e. fractured wells, partially penetrating wells, etc.). The present work examines the limitations of the superposi tion time concept as applied to buildup tests. It appears that, regardless of the flow regimes exhibited by the well reservoir system the derivative function with respect to the radial flow superposition time for a buildup test follows, at early time, the drawdown curve for the pressure first derivative function t*dp/dt, then, after a transition period, it follows the drawdown curve for the pressure second derivative function t2 * abs(d2p/dt2).
Inflow Performance Relationships for Solution-Gas Drive Horizontal Wells
Authors: Bendakhlia H. , Aziz K. 
Published: December 2007

Abstract
In 1968, Vogel used a computer program to predict inflow performance relationships (IPR) of a well producing from a wide variety of solution-gas drive reservoirs. In dimensionless form, these curves relating flowing bottom-hole pressures to oil production rates were found to share a common characteristic shape which was correlated by a parabola. Because Vogel studied cases of differing rock and PVT properties, his work became well accepted in the industry. Most of the papers published on inflow performance deal with vertical wells and should not be applied to horizontal wells without verification. There are no analytical models available at present to compute IPRs from two phase flow theory. In such a case, it is necessary to use numerical simulation. Unfortunately, most commercial black oil simulators do not include the feature necessary for predicting IPRs of horizontal wells.
In this paper1, two commercial simulators are utilized to develop IPRs for horizontal wells producing from solution-gas drive reservoirs. The development parallels the work of Vogel for vertical wells. First, a base case is considered with typical fluid, rock and reservoir properties. Then, variations from the base case are investigated. Changes from the base case, in fluid properties included variations in relative permeability and PVT properties. Changes in reservoir properties included variations in drainage area, pay thickness, and absolute permeability. Changes in well properties included variations in skin, well location, and well length with respect to reservoir boundaries. The resulting IPRs were made dimensionless in order to compare their curvature, or the rate of change of oil production rate with flowing bottom-hole pressure. These curves were found to be sensitive to the stage of reservoir depletion. However, they were not affected significantly by changes in the fluid reservoir, or well properties.
An attempt was made to develop a simple correlation to represent numerical results. Both Vogel's and Fetkovich's equations were tried, but neither of them fully reproduced the characteristic shape of the dimensionless IPRs. A new two-parameter equation, that results from combining the two previous equations was found to provide an adequate correlation.