bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Study of Stress in Devonian Shale: Part I—3D Stress Mapping Using a Wireline Microfrac System
Authors: Evans K. F. , Engelder J. T. 
Published: December 2007

ABSTRACT
We describe an experiment to characterize in detail variations in the state of stress within a horizontally-bedded sandstone/shale limestone sequence in western New York. The measurements were made using a new wireline-based "microfrac" system which, by its nature, permits frequent sampling of stress. Three wells, 1 km or so apart featured in the study. In one well, 43 intervals were tested to 1 km depth. The measured stress-profiles in all three wells show an identical pattern of stress variations. Two stratigraphic regimes of markedly different stress ratio are recognized which are separated by a transition zone. Within this zone variations in stress are clearly correlated with lithology.
Friction Pressure of Foamed Stimulation Fluids Evaluated With an On-Site Computer
Authors: Mack D. J. , Baumgartner S. A. 
Published: December 2007

ABSTRACT
Computerized monitoring of hydraulic fracturing treatments has been an accepted practice for several years. Not only can a continuous record of the treatment parameters be made, but the real-time bottomhole treating pressure can be determined without the use of a reference string or bottomhole pressure tool. However, to calculate the bottomhole treating pressure, the friction pressure of the fluid or slurry must be determined. For conventional, incompressible oil and water-based fluids friction pressure is a straightforward calculation since rate and proppant concentration are the main considerations. The friction pressure for foam fracturing fluids requires a more complex solution.
A computer van was used to monitor carbon dioxide and nitrogen foam treatments incorporating a reference string or bottomhole pressure tool. The foam friction pressure was determined from the continuous knowledge of foam composition and treatment parameters. The treatment data were used to develop a technique to predict foam friction pressures for bottomhole treating pressure calculations. This paper presents a foam friction pressure technique which allows the bottomhole treating pressure to be calculated without the use of a reference string or bottomhole pressure tool. The calculation of bottomhole treating pressure for a foam treatment incorporates a technique to correct the hydrostatic head pressure of carbon dioxide and nitrogen foams. In addition, the different effects of proppant addition on friction pressure between nitrogen and carbon dioxide generated foams are discussed.
Evaluation of Calcium Carbonate Scale Inhibitors for Prudhoe Bay, Alaska
Authors: Underdown D. R. , Newhouse D. P. 
Published: December 2007

ABSTRACT
The formation of calcium carbonate scale in the perforations and near well bore formation sandstone is one of the major factors affecting production in the Prudhoe Bay field. Previous work (1–11) has shown that squeeze treatments using certain phosphonate scale inhibitors help to control the formation of calcium carbonate scale in low water-cut wells. However, the desorption rate of the phosphonate from the formation may cause the effectiveness of the treatment to be decreased dramatically as the water-cut in the wells increases.
It has been observed that scale inhibitor squeeze treatments employing polymer-phosphonate blends appear to last longer in high water-cut wells than those treated only with phosphonate. This study evaluated the effect of various polymers on the desorption rate and inhibitive character of the phosphonate determined by Meyers (1) to be the most effective in inhibiting calcium carbonate scale in Prudhoe Bay.
Standard NACE scale inhibitor tests were conducted to evaluate the effectiveness in preventing scale for the various systems. Flow tests in formation cores were run to determine the feedback rate of the phosphonate from various systems. The core studies were monitored for the amount of phosphonate desorbed as a function of water-cut and total pore volumes of brine flowed through the core. Results showed that a high molecular weight maleic copolymer to be the most effective in decreasing the desorption rate of the phosphonate.
Two New Density Correlations
Authors: Chien M. C. H. , Monroy M. R. 
Published: December 2007

ABSTRACT
The Liquid density predicted by the Peng-Robinson (P-R) equation of state is often off by 10% or more at temperature and pressure conditions encountered in most reservoirs. To improve the density predictions, two new density correlations have been developed. The first correlation is based on the chain-of-rotators (COR) equation of state and the second is based on the three-parameter Peng-Robinson (PR3) equation of state. The COR correlation is applicable to wider pressure and temperature ranges, but is computationally expensive. It is suited for interpreting fluid-analysis data, where no extensive phase-behavior calculations are needed. On the other hand, the PR3 correlation is more limited in its application range, but is computationally more efficient. It is particularly suited for compositional reservoir simulation where many density calculations are repeatedly carried out.
In general, both correlations are comparable to the Standing-Katz correlation for liquid-density calculation and comparable to the P-R equation of state for vapor-density calculation. However, they are superior to the Standing-Katz correlation for liquid mixtures near critical points or liquid mixtures at high pressures. Overall, the COR equation of state gives an average prediction error of 1.9% for liquid densities and 2.7% for vapor densities, and the PR3 gives an average prediction error of less than 2% for both liquid and vapor densities. The required inputs are any two of the following properties for each pseudocomponent: molecular weight, specific gravity, and normal boiling point. This easy input requirement makes the correlations very attractive for engineering uses.
Phase Equilibria in Natural Gas Systems: Data for Two Helium-Bearing Natural Gases
Authors: Brandt L. Warren , Stroud Lowell , Miller John E. 
Published: December 2007

Abstract
A windowed phase equilibrium apparatus was used to obtain equilibrium vapor and liquid-phase samples of two helium-bearing natural gases at experimental conditions ranging from approximately -50 to -275 F at pressures from 100 to 500 psia. Helium contents of the gases studied are 2.5 and 0.75 per cent. The equilibrium samples were analyzed by means of a mass spectrometer and special helium analysis apparatus.
Loss of helium by solution in the condensed natural gas is a major concern in achieving high over-all efficiency in the separation of helium from natural gas by low-temperature methods. Data relating to helium solubility in condensed liquid phases and the condensation characteristics of the gases are presented and discussed. Equilibrium vaporization coefficients for methane, nitrogen and helium, obtained from experimental phase equilibrium data, also are given.
A sharp increase in demand for helium the last few years, urgently required in the United States' atomic energy and space programs, resulted in a helium shortage early in 1958. A recently completed plant at Keyes, Okla. has alleviated this condition temporarily, but it is expected that in a few years demand again will exceed supply. As a step toward meeting the nation's helium needs in future years, the U.S. Bureau of Mines Helium Activity of the Dept of the Interior-the only producer of helium in this country-announced in recent press releases a policy for conservation of this gas. Brief discussions of this policy have appeared. Long-range plans call for the construction of additional plants to remove helium from natural gas streams not going to fuel markets and to store the helium underground. It is possible that private industry will be interested in building and operating these "conservation" plants. "Crude" helium produced at these plants would be sold to the Government for storage.
To assist industry in evaluating their desired extent of participation in the program, the Bureau of Mines Helium Activity recently placed on open file a report presenting computed phase equilibrium data for the helium-bearing natural gas supplying the Amarillo, Tex., helium plant and experimental phase data for the gas supplying the Keyes, Okla., plant. Helium contents of these gases are 1.8 per cent at Amarillo and 2.1 per cent at Keyes. A later open-file report presented experimental-phase data for a natural gas containing 0.7 per cent helium and is of interest because this helium content is expected to be representative of natural gases to be processed for helium in the conservation program.
Effect of Tarmat on Reservoir Behavior: Reservoir Simulation Case Studies
Authors: Acharya U. B. 
Published: December 2007

ABSTRACT
It is fairly common to find tarmat or heavy oil at the base of hydrocarbon column in many reservoirs in the Middle East. Reservoir simulation field study of one such reservoir, namely Reservoir "A" of a field in this region is described in this paper. Another example of such a reservoir (Reservoir "B") is also briefly discussed.
The tarmat which is present at the base of the hydrocarbon column controls the degree of intercommunication between the aquifer and the oil column. In the study of Reservoir "A", the approach for simulating the tarmat behaviour was mainly to modify the interblock transmissibility whereas in the study of Reservoir "B", the approach was to modify the relative permeability.
Both the approaches gave good results and clearly indicated that in both the reservoirs, initially, the tarmat acted as a permeability barrier and hence the reservoirs behaved as depletion drive reservoirs. Afterwards, with continued production, the pressure differential between the aquifer and the oil zone was substantial enough to breakdown the tarmat layer. Several prediction schemes were made on both reservoirs with the status of tarmat as of the end of the history match. The optimum production scheme for both reservoirs is water injection above the tarmat. For Reservoir "B", pilot water injection has already commenced.
Laboratory Miscible Displacement Study in Arabian Carbonate Cores
Authors: Asar H. K. , Satman A. , Saner S. 
Published: December 2007

ABSTRACT
Determining the applicability and type of the EOR method to maximize oil recovery from carbonate reservoir containing Arabain heavy crude is the subject of this study. Various EOR displacement experiments including waterflooding, CO2 flooding, enriched gas injection and LPG injection were carried out. Results of laboratory theoretical and experimental studies indicated that hydrocarbon miscible flooding could maximize oil recovery.
Following necessary preliminary studies, a systematic series of miscible flood displacements of the Arabian heavy oil using a slim tube apparatus and a natural core displacement apparatus was performed.
In this paper, findings from a variety of laboratory slim tube and natural core flooding experiments are Discussed and analyzed. Factors influencing the mechanism of miscible displacement, as a secondary process replacing conventional water flooding and as a tertiary process recovering waterflooding residual are elucidated.
Abu Dhabi Offshore Khuff Gas Completions Using Exotic Metallurgy
Authors: Ray D. R. 
Published: December 2007

ABSTRACT
The use of exotic metallurgy for the completion of deep, hot, sour gas wells is growing. The design of such completions must consider alloy selection, equipment specification, quality assurance, acidizing procedures and packer fluids. These aspects are discussed in relation to a recent Khuff gas project in Abu Dhabi.
Infill Drilling Enhances Oil Recovery in Egypt's First Waterflood Field
Authors: Mahmoud M. L. 
Published: December 2007

ABSTRACT
This paper presents both the primary and secondary historical performance during the first 20 years for the Kareem zone, the major producing Horizon of the giant Egyptian oil field El Morgan. The justifications and qualifications pertaining to the initiation of major peripheral waterflood project for the first time in Egypt are reviewed.
The paper emphasizes the results of a recent comprehensive geoiogical/engineering study where an extensive multidevelopment plan including 35 new wells was recommended to improve both areal and vertical sweep. Results available todate demonstrate that infill drilling in a mature waterflood can enhance oil recovery both in terms of accelarating production and adding new reserves.
Variation of a Natural Sandstone Reservoir Element: An Objective Analysis of Core Measurements
Authors: Greenkorn R.A. , Johnson C.R. 
Published: December 2007

Abstract
Samples from 39 complete cores of a natural sandstone reservoir 150-ft square and about 8-ft thick were analyzed for variation and change in variation or gross reservoir thickness, permeability and porosity. For objective analysis, the gross reservoir thickness is defined as that entire interval in which flow is confined, regardless or the permeability or porosity or the included rock strata. This thickness is measured directly from cores. Ten randomly spaced and oriented horizontal plugs were cut from each core. Each plug was saturated with reservoir water and permeability was measured with a constant-head discharging apparatus. Porosity of three or each suite of plugs was determined by the liquid saturation method.
Mean squares, measures of variation, show the natural variation of the thickness, permeability and porosity for different groups or the data. Comparison of the mean squares of these groups demonstrates the change of variation. This application or data control methods shows these properties to have a large variation, and change or variation, in a natural reservoir.

Introduction
To interpret and predict fluid flow in a natural rock system, it is necessary to know not only the correct average values of thickness, permeability and porosity, but also the natural variation of these properties. Of equal concern is the change of variation in the reservoir. That is, are the heterogeneities heterogeneously distributed? Unfortunately, the degree of variation of thickness, permeability and porosity of most oil fields or any other natural reservoir is unknown.
The first objective of this study, then, is to ascertain the variation of thickness, permeability and porosity within a small segment of a natural reservoir sandstone. The data were obtained from a brine-saturated upper Pennsylvanian sandstone which is 250-ft deep. Thickness and permeability were measured from 39 complete cores from a 150-ft square of this sandstone, and porosity from 31 of these. The average thickness is about 8 ft, the average permeability is 0.4 darcy and the average porosity is about 24 per cent. Location of the core holes, numbered in the order they were drilled, is shown in Fig. 1.
The second objective of this study is to analyze the variation of thickness, permeability and porosity to establish the magnitude of the changes of variation.
Effects of Reservoir Heterogeneity on Performance
Authors: Hopkinson J.L. , Natanson S.G. , Temple A.P. 
Published: December 2007

Abstract
The paper deals with the application of several idealized models in the diagnosis and description or the effects attending flow in a heterogeneous reservoir. The types of heterogeneity considered are restricted to discontinuous vertical and horizontal change in flow parameters and, to some extent, the occurrence of fracturing.
The models are described and the characteristic behavior of each model discussed. The results of the mathematical analyses of the models are then applied to two field cases.
First, the pressure behavior of a single well in an undeveloped reservoir is analyzed to illustrate the degree to which the application of idealized models can detect the type and extent of heterogeneity present.
Secondly, the model results are applied in the study of a vertically heterogeneous field.
Finally, conclusions are presented which summarize the possible applications of the model theories to field behavior.

Introduction
The investigation into the effects of various types of reservoir heterogeneity arose from the study of a particular sandstone field. The reservoir formation, some 340-ft thick, consists of sandstone, siltstone and shale; the variation in permeability is much more pronounced vertically than horizontally. The structure is a shallow anticline; the aquifer is of considerable extent on one flank but is believed to shale out rapidly on the other. Up to the present, flow has been single-phase. A structure map of this field and a typical vertical cross section are shown in Figs. 1 and 2, respectively.
A general investigation was carried out to assess the effect which the different types of heterogeneity observed in the reservoir would have on the field's performance. This investigation is the subject of the present paper.
DEVELOPMENT OF MODELS

Preliminary Considerations
The first approach to the problem of flow in heterogeneous media consisted of simulating a 2-layer radial system in single-phase flow by a capacitance-resistance network. The analogue was two-dimensional and consisted of 8 × 13 mesh points. The radial extent of the physical system simulated was approximately 100 times the well radius, and the thickness of each layer was 18 times the well radius. The two layers had the same expansibility and a permeability ratio of 1:10. Cross flow between layers was allowed.
The Construction of Curvilinear Co-ordinate Grid Systems for Reservoir Simulation
Authors: Ferguson W. I. , Wadsley A. W. 
Published: December 2007

Abstract
The construction of optimally orthogonal grid systems has, in the past, been a somewhat ad-hoc procedure. In this paper, several new methods of deriving grid systems for full field and symmetry (production) element, curvilinear models are described. The basis of the approach to constructing full field curvilinear models assumes that the engineer has identified those aspects of the reservoir geometry to which the simulation grid will correlate or conform. The "primary" and "secondary" grid lines to the orthogonal grid typically should conform to various geological features such as faults, reservoir boundries, formation top and/or bottom depth contours and fluid contacts.
The methods described to construct full field grids include: contour-to-grid interpolation and grid-to-contour construction procedures which define a global (conforming) potential field in the reservoir from which the global orthogonal grid is constructed;the use of the Boundary Element Method to calculate a global potential field to likewise construct a globally orthogonal grid;the use of geometric construction procedures, including dot-product minimization and rubber banding to construct primary and secondary line sets from engineer defined correlating lines.
The use of the BEM in constructing curvilinear grids for production elements based upon isopotential and streamline definition is also described in detail.
Evaluation of Single-Layer Transients in a Multilayered System
Authors: Ehlig-Economides C. , Joseph J. , Erba M. , Vik S. A. 
Published: December 2007

ABSTRACT
Recent developments in well testing have focused on obtaining the properties of each layer in a multi-layered reservoir. Quantification of the dynamic reservoir description includes determination of the layer permeabilities and skins, effective drainage boundaries, and zone average pressures. The subject of this paper is a new well test procedure for acquiring the transient flowrate and pressure response of any single layer in a commingled system. Convolution of the bottom hole flowing pressure with the layer flowrate produces a response function equivalent to the pressure transient that would be measured if the layer were packed off in the well.
A major advantage of this test is that wellbore effects on the transients are minimized, thus enabling reservoir characterisation in the vicinity of the wellbore that is not possible by any previously reported means. Hence, the early time response affords the possibility of quantifying partial penetration skin or the radial extent of an altered zone.
A second advantage is the possibility for long duration testing of the single layer with little interuption in the well production. If the interval tested by this method is not communicating vertically with adjacent layers in the reservoir, the recorded transients can be evaluated for reservoir heterogeneities such as dual porosity behavior.
Improved Reservoir Description through the Integration of Seismic, VSP, and Well Logs
Authors: Roberts D. E. , Winchester A. J. 
Published: December 2007

ABSTRACT
A Reservoir Modelling workstation that allows fast access to, and integrated interpretation of data from the disciplines of Geophysics, Geology and Reservoir Engineering is being developed. Currently, from an initial overall reservoir 3-D geometry description (derived from seismic & log data), the model is elaborated to include more geological detail through the extension of single well geology diagnostic to the entire reservoir. A longer term objective is to integrate pressure and flow information with this static description to produce a 3-D dynamic reservoir model. Some of the techniques that have evolved during development of the static model have been applied to a North Sea oil field. Data used in this study included 3-D surface seismic, VSP surveys from 12 wells, and well log information from 28 wells.
Numerical Simulation of the North Sea Fulmar Oil Field: Evaluating Reservoir Depletion Strategies
Authors: Valenti N. P. , Buckles R. S. 
Published: December 2007

ABSTRACT
The Fulmar field, located in the Central North Sea, began production in 1982. This thick reservoir covering an area of only 10 sq. km has an 0IP of approximately 850 MB0 (135 × 106 m3). Initial reservoir pressure was 5700 psi (39,300 kPa) (3900 psi above saturation pressure, 2200 psi above hydrocarbon gas-oil minimum miscibility pressure, and, 1000 psi above hydrostatic pressure). During the first two years of operation, the field pressure dropped more than 1000 psi (6,900 kPa), a secondary gas cap developed because of gas injection, and the oil-water contact advanced up to 100 ft (30 m). A 3-D, 3-phase, black-oil numerical model of the field was developed in 1984 based on 27 months of production data to project future performance with alternative development and depletion strategies.
Interesting features of the simulation include: miscible gas injection into an undersaturated oil reservoir, pressure communication between fault blocks with different original oil-water contacts, the modeling of gas and water coning at wells located near the dome shaped crest of the structure, and compliance with facility, drilling and recompletion constraints, as maintained by rate and well management routines in the simulator.
A description of the 5000 block numerical model is provided along with the history match and results of simulation predictions. Conclusions drawn from this work include the following: (1) A production plateau of at least 135 kBD (894 m3/h) can be maintained until 1987 without additional drilling; (2) this plateau can be extended an additional three years through further drilling, recompletions, and re-distribution of water injection; and (3) improved oil recovery from the Clyde sand unit can not be achieved simply by modifying the production-injection strategy for that zone.