bluuebunny/crossref_metadata_2025_split huggingface dataset:
Design Concepts for Offshore Produced-Water Treating and Disposal Systems
Authors: Arnold Kenneth E. 
Published: December 2007

Summary
The general theories governing, produced-water treating equipment design are presented and qualitative conclusions drawn from the resultant equations. The design and use of various common components used in offshore produced-water treating systems are discussed.

Introduction
The engineer charged with designing an offshore produced-water treating and disposal system is faced with an almost insurmountable problem. While the endpoint is fixed for the design, usually little is known about the quality of the water that must be treated. The basic data set forming the basis of the current U.S. discharge guidelines is contained in a 1974 study conducted for the Offshore Operators Committee (OOC). Each type of final treating device was analyzed separately with specific conclusions drawn for pits, tanks, flotation systems, plate coalescers, fibrous media coalescers, and loose media coalescers. The report concluded: "Flotation units and loose media coalescers were found to produce the lowest mean effluent oil concentrations of the processes studied. Flotation is a widely used process and is applicable almost universally. Loose media coalescers were not selected to represent exemplary performance because of operating problems at many locations." The validity of this conclusion concerning loose media coalescers subsequently was verified by an in-depth study conducted by the OOC. The U.S. EPA analyzed these data, plus additional data furnished from industry and from EPA-conducted field verification studies, and arrived at their interim guidelines of 48 mg/L. The derivation of discharge quality based on exemplary performance of flotation systems does not imply that the installation of a flotation system will necessarily meet this criterion. In determining "exemplary" flotation systems the EPA eliminated many data. For example, in the original OOC study, about 25 % of the flotation systems analyzed had mean effluent-oil concentrations in excess of 48 mg/L. Thus, any water treating system that includes a flotation unit must be designed carefully for the conditions expected at that particular facility. Similarly, it is not necessary to install a flotation unit in each water treating system. The EPA-specified effluent limitations can be achieved with less sophisticated equipment under certain circumstances. W.L. Berry states:
" Not all treatment processes are applicable at all locations. Performance of water treatment systems is not only a function of retention time, design parameters, use of chemical coagulants…but is also influenced by a number of factors most of which the operator has little or no control over including: water characteristics, crude type and solubility, degree of entrained oil emulsification, sizes of the entrained oil droplets, and suspended solids concentrations and characteristics. [Because of these factors,] if identical treatment systems are installed at two different locations, the average produced-water effluent oil content may be quite different."
JPT
P. 276^
Limitations on Pressure Predictions for Water-Drive Reservoirs
Authors: Simons L.H. , Spain H.H. 
Published: December 2007

Abstract
Five water-drive fields, for which pressure predictions had been made within a few years after discovery, were re-studied when four to five years of additional pressure and production data became available. It was found that forecasts of the pressure in water-drive reservoirs may be subject to considerable uncertainty. Predictions can be erroneous when there is insufficient pressure history to define the characteristics of the aquifer, and when there are errors in the pressure, production or geologic data.

Introduction
The efficient operation of an oil or gas reservoir requires that the important characteristics of the reservoir be determined soon after its discovery. It is especially desirable to evaluate the pressure-production relationship quickly, for this relation-ship provides a basis for deducing the type of production mechanism that is operative, and for making pressure predictions. The pressure predictions, in turn, provide a basis for calculating efficient rates of production, determining whether water or gas should be injected, etc.
The importance of pressure prediction is such that forecasts should be made as accurate as possible, and the limits of error well defined. Historically, pressure forecasts for some fields have proved very accurate, while for others the forecasts were so erroneous that they resulted in the adoption of wrong, or at best, unnecessary production practices.
Pressure predictions made for water-drive fields are especially subject to error. Accurate forecasting for these fields requires that much be known not only about the reservoir proper but about the adjacent water-filled rock as well. The water-containing rock, or aquifer, may extend for many miles, and often there is only meager data regarding its thickness, permeability and porosity. Much of the information must be inferred from the previous pressure behavior of the reservoir. A brief pressure history may provide little information about the characteristics of the aquifer. Hence, pressure predictions made early in the life of water-drive fields can be incorrect.
Transition Time of Cement Slurries Between the Fluid and Set States
Authors: Sabins Fred L. , Tinsley John M. , Sutton David L. 
Published: December 2007

Abstract
Previous work on annular gas flow1–4 has shown that the behavior of cement between its fluid and set states is the controlling factor that may allow gas entry. This transition phase of cement previously has not been recognized in slurry design since its importance was not understood fully and since test procedures for its definition had not been presented or established.
To predict the occurrence of annular gas flow and to design cement slurries capable of helping to prevent annular gas flow, it is necessary to define the slurry characteristics at the beginning and end of this transition period as well as the length of time of the transition state, Test techniques have been developed to study the start of this transition period. Additional tests have been conducted to define the condition of cement required to prevent gas entry. The test techniques developed to define this transition period of a cement slurry are described.
Numerous job variables such as pumping time, placement time, slurry composition, and circulating temperature and pressure were investigated to evaluate their influence on transition time. A method for using transition time and static gel strength (SGS) development data to help predict annular gas flow and to evaluate annular gas flow control materials is discussed.
Fractured Reservoir Simulation
Authors: Thomas L. Kent , Dixon Thomas N. , Pierson Ray G. 
Published: December 2007

Abstract
This paper describes the development of a three-dimensional (3D), three-phase model for simulating the flow of water, oil, and gas in a naturally fractured reservoir. A dual porosity system is used to describe the fluids present in the fractures and matrix blocks. Primary flow in the reservoir occurs within the fractures with local exchange of fluids between the fracture system and matrix blocks. The matrix/fracture transfer function is based on an extension of the equation developed by Warren and Root and accounts for capillary pressure, gravity, and viscous forces.
Both the fracture flow equations and matrix/fracture flow are solved implicitly for pressure, water saturation, gas saturation, and saturation pressure.
We present example problems to demonstrate the utility of the model. These include a comparison of our results with previous results: comparisons of individual block matrix/fracture transfers obtained using a detailed 3D grid with results using the fracture model's matrix/fracture transfer function; and 3D field-scale simulations of two- and three-phase flow. The three-phase example illustrates the effect of free gas saturation on oil recovery by waterflooding.
Proppant Settling Correlations for Non-Newtonian Fluids Under Static and Dynamic Conditions
Authors: Shah Subhash N. 
Published: December 2007

AbstractThis paper presents a new approach for analysis of prop-pant settling data in non-Newtonian pseudoplastic fracturing fluids and develops drag coefficient correlations as a function of fluid model parameter n′. Results of experiments with these fluids under static as well as dynamic conditions are discussed. A wide range of n′ and particle Reynolds number is investigated.It is shown that at low-particle Reynolds numbers the fluid model parameter n′ has a significant effect on prop-pant settling velocity. This effect diminishes at higher particle Reynolds numbers. The dynamic settling velocity data agree reasonably well with the correlations developed from static velocity data. Further, experimental results of earlier investigations agree well with the correlations of this study.
Digital Log Calculation of the Compensated Density Log
Authors: Head Mickey P. , Barnett Michael E. 
Published: December 2007

Summary
Calibration and recording of the compensated density log with a digital logging system are discussed. The mathematical definition of the spine and ribs and the technique of computing compensated bulk density and amount of correction from tool count rates are explained.

Calibration Standards
The primary calibration standard for the compensated density log is freshwater-filled limestone blocks. The secondary calibration standards are blocks of aluminum and magnesium alloys of known composition. Since the compensated density log responds to the electron density index, Pe, a relationship exists that converts the electron density index to apparent bulk density, Pa.
Pa = 1.0704, ...................(1)
where
Pa= apparent bulk density as read by the tool, and Pe= electron density index.
By quantitative analysis of the two secondary blocks, the electron density index was computed and converted to apparent bulk density by Eq. 1. The values of apparent bulk density (more commonly known as bulk density) for the two blocks are 2.59 g/cm3 for aluminum and 1.71 g/cm3 for magnesium.

Spine Calibration
Calibration of the compensated density log with the Direct Digital Logging unit is performed by placing the tool in aluminum and magnesium blocks, accumulating the counts for 3 minutes in each block, and averaging the count rates. The count rates for the aluminum block (short-spaced and long-spaced counts/sec) define for each tool the response at a bulk density of 2.59 g/cm3, and the count rates in the magnesium block (short-spaced and long-spaced counts/sec) define a bulk density of 1.71 g/cm3. Fig. 1 shows the relationship of the magnesium block, the aluminum block, and the linear spine through the two calibration points. First, the four count rates are converted to logarithms where Las is the log of the short-spaced aluminum counts/sec, Lal is the log of the long-spaced aluminum counts/sec, Lms is the log of the short-spaced magnesium counts/sec, and Lml is the log of the long-spaced magnesium counts/sec. The slope of the spine is
Lml - Lal m spine = .....................(2) Lms - Las
The y intercept of the spine is
b spine = Lal - m spine (Las)................(3)
Since the values of bulk density and calibration count rates are known for both the magnesium and aluminum blocks, the ratio of difference in density to distance on the spine is
F spine = ..........(4)
F spine, m spine and b spine are stored on the digital program tape for a matched tool and source. These program tape for a matched tool and source. These calibration values are read from the program tape and are placed in memory when the log is to be run. placed in memory when the log is to be run. JPT
p. 167
Pressure Transient Behavior of Non-Newtonian/Newtonian Fluid Composite Reservoirs
Authors: Lund O. , Ikoku Chi U. 
Published: December 2007

Abstract
Pressure transient theory of flow of non-Newtonian power-law fluids in porous media is extended to non-Newtonian/Newtonian fluid composite reservoirs. This paper examines application of non-Newtonian and conventional (Newtonian) well test analysis techniques to injectivity and falloff tests in wells where different amounts of non-Newtonian fluids have been injected into the reservoir to displace the in-situ Newtonian fluid (oil and/or water).
Early time pressure data can be analyzed by non-Newtonian well test analysis methods. Conventional semilog methods may be used to analyze late time falloff data. The location of the non-Newtonian fluid front can be estimated from well tests using the radius of investigation equation for power-law fluids. An equation for calculating shear rates and apparent viscosities for power-law fluids in reservoirs is presented. An example problem is used to illustrate observations and solution techniques.
An Analytical Solution for Linear Waterflood Including the Effects of Capillary Pressure
Authors: Yortsos Y. C. , Fokas A. S. 
Published: December 2007

Abstract
In this paper we develop exact solutions for a model linear [one-dimensional (1D)] waterflood that includes the effects of capillary pressure. We show that at constant injection rates an exact solution is possible for a water/oil displacement process, for which the mobility ratio has the functional form (1)kroμwkrwμo=F(S−Sor1−Swr−S),
where S is the oil saturation and F is a parameter that can be taken as the water-to-oil viscosity ratio.
Explicit analytical expressions for the oil saturation distribution as a function of position and time are derived that account for the effects of capillary pressure. The solution is expressed in terms of F and a dimensionless parameter, β2, that denotes the relative magnitude of viscous to capillary terms. At high injection rates (β→∞), the solution reduces to the familiar Buckley-Leverett expressions, including the shock front solution when F&gt; 1. From the analytical results one can calculate the capillary effects on the performance of the model waterflood.
This work, which for the first time presents an analytical solution for a linear waterflood that includes capillary effects, finds applications in two areas. First, it can be used to describe explicitly the performance of the model waterflood at low injection rates (small β), where the existing approximate solutions fail to account for the large capillary terms. Second, it can be used to check approximate analytical (such as the Buckley-Leverett), asymptotic, and numerical solutions.
A New Approach Toward Elimination of Slug in Shaped Charge Perforating
Authors: Delacour J. , Lebourg M.P. , Bell W.T. 
Published: December 2007

Abstract
Since the advent of the perforation flow laboratory, increased attention has been focused on new designs of shaped charges as applied to oilwell perforating. Data derived from the flow laboratory, in which charges are subjected to simulated down-hole tests, indicate that serious perforation plugging often exists due to the entrance of slugs into the perforated hole.
The slug or "carrot" is an intrinsic part of the jet process and its adverse effect is inherently characteristic of many commercial shaped charges which otherwise exhibit excellent performance properties.
Numerous approaches have been tried throughout the industry in an effort to prevent this flow-impeding slug from entering the perforated hole. Yet, publicly conducted tests indicate that none of these devices are entirely successful when applied under the clearance and pressure conditions for which the charges are designed. This paper deals with a new, direct approach toward the elimination of the slug or carrot in shaped charge perforating.
Herein is described a newly developed bimetallic liner for shaped charges, which when fired under pressure leaves no slug in the perforated hole and yet maintains the high performance of the conventional-type charge.

Introduction
During the past few years the testing of shaped charge tools, as applied to oilwell perforating, has evolved from simple surface shooting to tests conducted in a flow laboratory in which a study of the charge could be made under simulated down-hole conditions. In the flow laboratory, pressures and temperatures were elevated prior to firing the charge into a target of medium-hard sandstone material. An elaborate system was devised for firing the charge under various fluids and differential pressures. Provisions were made for actually "flowing" the perforated hole under controlled conditions. It was at this point that the term slug or carrot really emerged into oil-well perforating vernacular. While it had been noted that a slug of charge liner material often entered the perforation, these plugged test targets had drawn little attention. Now in the flow laboratory, it was found that this obstructing slug reduced the resultant flow through the perforation to as little as one-half that normally expected! It was then clear that the slug must be either eliminated from the shaped charge entirely or reduced to such proportions that it would be ineffective in plugging the perforated hole.
Problems of the International Petroleum Industry in 1957
Authors: Chapman A.H. 
Published: December 2007

Introduction
American oil companies both large and small are commencing to devote more of their energies and their capital to production operations outside the United States. The recent granting of new concessions in Venezuela, North Africa, and Central America, have added many new names to the list of companies working abroad. In view of this healthy new development, it is appropriate at this time to review some of the problems which these companies will have to face in conducting their business successfully.

World Crude Demand
In 1956 free world production of oil averaged about 14,825,000 B/D, which represented an increase of 8 per cent over the average in 1955. This percentage increase would doubtless have been greater had it not been for the unfortunate closing of the Suez Canal and the necessity of rearranging shipping routes. Based on estimates of prosperity growth, many economists believe that for the next decade or so we can look at world increases in demand in the range of 8 to 10 per cent annually. We are, therefore, looking at a doubling of crude oil production over the next decade. The only thing which will interfere with this tremendous rate of growth will be war or some kind of nationalistic brake applied against the free use of energy throughout the world.
Against this estimate of increased demand we are witnessing the greatest world-wide exploratory effort that our industry has ever known. New techniques in geophysics, geology, and production are making this effort remarkably successful.
In spite of the plentiful crude oil supply position which exists today, both in the United States and abroad, these vigorous programs are likely to result in additions to world crude oil reserves. Many of these additions will be made by companies which heretofore have not been important producers outside of the United States and others who are in foreign work for the first time.
Reaction Kinetics of In-Situ Combustion: Part 2—Modeling
Authors: Fassihi Mohammad Reza , Brigham William E. , Ramey Henry J. 
Published: December 2007

Abstract
A model is proposed to analyze and differentiate between crude oil/oxygen reactions at different temperatures. The results of this analysis along with correlations of apparent hydrogen/carbon (H/C) ratio and molar carbon dioxide/carbon monoxide (CO2/CO) ratio indicated three major reactions at different temperatures. Low-temperature oxidation (LTO) appears to occur between the gas and liquid phases. Middle-temperature fuel deposition reactions appear to be homogeneous. The latter was found to be the rate-determining step in clean sands.
Natural cores from the reservoirs were found to have different kinetic behavior than the clean sand matrices for these reasons: (1) metallic additives lower the activation energy of the combustion reaction and hence shift the rate-determining steps, and (2) clay and finer sands adsorb more fuel.
The proposed kinetic model was found to be applicable to the five oils tested and hence may be generalized for application to any oil.
Pressure Decline Analysis for Prediction of Gas Reservoir Volumes
Authors: Hales H.B. 
Published: December 2007

Summary
This paper describes a new method for combining pressure decline data and production rates to determine original gas volumes for gas reservoirs. The method is illustrated by application to actual field data. The new method is similar to the classical analysis which extrapolates a plot of p/z vs. cumulative production to the original gas in place. However, it allows for the influx of water into the original reservoir volume in a more rigorous manner than previous methods. It also provides an estimate of the reliability of the predicted original-gas-in-place values.

Introduction
Pressure decline analysis has become a basic reservoir engineering tool, particularly for gas reservoirs. It is readily apparent from the gas law of physical chemistry that the reservoir-pressure/gas-deviation factor ratio (p/z) should decline linearly with cumulative reservoir production, provided the reservoir is highly permeable and has a constant volume. Unfortunately, many reservoirs do not have a constant volume as a result of water influx that occurs with declining reservoir pressure. Most methods of accounting for this complication are based on the early work of van Everdingen and Hurst. Van Everdingen and Hurst used the Laplace transform to solve the partial differential equation governing single-phase radial flow in porous media and were able to relate production at an internal reservoir boundary to the pressure at that boundary. Many investigators have used this solution to account for water influx at the edge of a reservoir. These include the well-known techniques of van Everdingen et al., Hurst, Carter and Tracy, and Odeh and Havlena. The literature abounds in applications and variations of these methods.These methods can be visualized as modeling reservoirs as large tanks which gradually fill with water as the tank pressures decrease. Many workers have questioned the validity of such a model. In particular, Chierici et al. and McEwen have investigated the errors in the predicted hydrocarbon volumes that result from the unavoidable errors in the pressure measurements. Furthermore, Bruns et al. have shown that the effects of water influx on the nature of the pressure decline curve are diverse. Water influx can cause a concave upward pressure history, a concave downward pressure history, or an S-shaped curve. Pressure decline with strong water influx also can resemble closely the straight-line pressure decline of a depletion-type reservoir.This work is an attempt to overcome the short- comings of previous methods. The improvements are twofold. First, the model includes a moving water/hydrocarbon interface. In analogy with previous models, this allows a nonconstant tank volume. Second, the method provides not only a best estimate of the hydrocarbons in place but also an estimate of the accuracy of these results.

Theory
This work involves the development and use of a model that predicts reservoir pressure as a function of cumulative production and time. A schematic of the model is shown here.
JPT
P. 2261^