bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Effect of Interfacial Films on the Displacement of Oil by Water Porous Media
Authors: Bourgoyne A.T. , Caudle B.H. , Kimbler O.K. 
Published: December 2007

Abstract
Many crude oils contain surface active compounds that will collect at an oil-water interface to form a rigid film. Since interfacial forces are important in the displacement of oil by water in reservoir rock, the presence of rigid films in the reservoir could alter the recoverable oil by water invasion. Experimental work in water-wet Porous media indicates that the presence of interfacial films decrease the amount of recoverable oil in highly heterogeneous porous medial but usually has no effect in nearly homogeneous systems.

Introduction
It is generally accepted today that petroleum is derived from sedimentary organic matter. Meinschein, working with several soils and recent marine deposits, found that nonhydrocarbon organic compounds, similar to compounds found in living things, made up about 80 percent of the extracted organic material. Porphyrins, percent of the extracted organic material. Porphyrins, amino acids, and sulfur compounds were the main constituents found. Amino acids are the basic units of protein and, as such, are an essential part of all organisms. Erdman shows several possible reactions for the conversion of amino acids and carbohydrates to the common low molecular weight hydrocarbons. Baker, as well as Hodgson and Hitchon, gives evidence that complex natural organic compounds act as "solubilizers" to allow the movement of hydrocarbons by ground water from the source bed to the reservoir. Trace amounts of soluble polar organic compounds are usually found in reservoir water. Thus, the high molecular weight surface active material found in crude oils (such as the porphyrinmetal complexes, esters, ketones, aldehydes, porphyrinmetal complexes, esters, ketones, aldehydes, carboxylic acids and organic nitrogen compounds) are probably remnants of the organic matter from which the crude oil originated.
With many crudes, the presence of significant quantities of surface active material can result in the formation of a rigid film at an oil-water interface. If the interfacial area is reduced, the film will often wrinkle, indicating the formation of a solid membrane. The presence of film material has an important effect in the formation and stability of oilfield emulsions, and in the deposition of paraffin in oilfield equipment. Fig. 1 is a paraffin in oilfield equipment. Fig. 1 is a photograph taken during a microscopic examination photograph taken during a microscopic examination of film material obtained after breaking a water-in-oil emulsion. Shown in the photograph are ruptured film sacs that once stabilized two droplets of water in the emulsion.
Interfacial forces are important in the displacement of oil by water in reservoir rock, and the presence of rigid Elms could alter these forces. Since much of the available laboratory data on the displacement of oil by water in porous media was obtained using relatively pure water and oil, the effect of rigid films should be known if we are to apply these data to reservoir systems.
Concerning the Calculation of Inflow Performance of Wells Producing from Solution Gas Drive Reservoirs
Authors: Standing M.B. 
Published: December 2007

Estimating probable flow rates of wells producing from solution gas drive reservoirs is a problem frequently encountered by petroleum engineers. One approach to an answer involves the simultaneous solution of the well's inflow performance relationship (IPR) and the rate-dependent pressure losses in the well tubing, surface flow lines, and chokes. Nind covers very nicely several graphical methods of accomplishing the simultaneous solution. This note presents relationships that can be used to obtain IPR presents relationships that can be used to obtain IPR curves applicable to bounded solution gas drive reservoirs in which the average reservoir pressure is less than the reservoir fluid bubble-point pressure. Vogel's dimensionless IPR equation is the basis for the development. An example illustrates how future IPR curves can be developed from a current productivity index value.
Vogel developed a general dimensionless relationship for wells producing under conditions outlined above and under pseudosteady-state conditions given by Eq. 1.
(1) = 1 - 0 .2 - 0 .8 ,
where
qo = stock-tank oil producing rate, B/D pwf = wellbore flowing pressure, psi pwf = wellbore flowing pressure, psip = average reservoir pressure, psi p = average reservoir pressure, psi qo max = maximum rate the well would producefor conditions of pwf = 0.
Eq. 1 can be rearranged to
= ...............(2)
The productivity index of a well is defined by
(3) J =
Substitution of Eq. 3 into Eq. 2 yields
(4) J =
Physical conditions inherent in Eq. 4 are that reservoir Physical conditions inherent in Eq. 4 are that reservoir gas and oil saturations, as well as reservoir pressure, vary with distance away from the wellbore, and that the well's skin factor is zero.
Let us now consider the situation in which fluid saturations are the same everywhere in the reservoir. This is analogous to a "zero drawdown" situation. Let J* be the well's productivity index under these conditions. Mathematically,
(5) lim J J* =
Applying the limit conditions to Eq. 4 yields
(6) J* =
P. 1141
Polywater and Reservoir Engineering
Authors: Davidson L.B. 
Published: December 2007

Research by Deryagin and Fedyakin during the last decade showed that a solid surface can influence the properties of an adjacent liquid to depths on the order properties of an adjacent liquid to depths on the order of a micron. In particular they found that viscosity increases substantially near the solid-liquid interface.
In many porous materials pore throats on the order of a few microns are quite common. Consequently, "wall effects" may significantly alter viscosity of fluid flowing through such materials and it becomes important to determine how seriously current models of flow in porous media are affected by this phenomenon. phenomenon. As a simple illustration of the role played by "wall effects," consider flow through a single capillary of radius r. Assume that the viscosity at the center of the tube has a constant value, and near the tube wall a constant value . The viscosity changes fromto at the radial position us. The "permeability" of the tube is defined for a Newtonian fluid by:
=, .........................(1)
where eff is an effective viscosity for flow through the tube. If there were no "wall effect" eff would equal .
To measure the single-tube "permeability" it is customary to carry out flow tests at constant pressure drop, p, and to compute "permeability" using the viscosity of the bulk fluid, . Let this computer "permeability" be denoted as k calc. Then
= .......................(2)
Now, let
Xr = and X = .
Then it is not difficult to show that for a Newtonian fluid
(3) 4 = X + (1 − X )Xr
The deviation between the calculated and effective values is a linear function of the ratio X . The slope of the line tends to zero as Xr increases. As a particular example, suppose Xr = 0.5 and the viscosity particular example, suppose Xr = 0.5 and the viscosity is twice as large as the usual value . Then the calculated "permeability" of the tube is equal to 53.1 percent of the effective value. percent of the effective value. This simple example shows that the near-surface structuring of liquid could significantly influence flow behavior in porous materials. Whether or not this is actually true depends on the depth of the liquid structuring, the magnitude of changes in fluid properties resulting from the structuring, and the percent of area available to flow that is affected by structuring. The last factor is determined by the pore-size distribution of the system.
P. 1263
Predicting Pore Compressibility of Reservoir Rock
Authors: Marek B.L. 
Published: December 2007

The effective pressure in a reservoir is characterized by two sets of stress conditionsthe stress condition at the time the reservoir is discovered and the stress condition existing during the pressure decline period due to production of reservoir fluids. Since correlations of pore compressibility presented in literature may have been obtained by several different types of laboratory testing procedures, a technique of converting these various procedures to a reference set of stress conditions is required for reservoir evaluation.
With the method presented here we can quickly interpret results of various pore compressibility measurements regardless of the testing procedure used.
The limits of effective stress at the time of discovery of the reservoir, according to van der Knapp, can be described by the equations:
effective stress = = ( )
for "passive" earth pressure condition, and
effective stress =
for "active" earth pressure condition. In these equations:Pz = overburden pressure, psipi = initial pore fluid pressure, psi= pore fluid stress, psi= mean external stress, psiA, B = constants related to the Mohr failure diagram
van der Knapp suggests that the "passive" stress condition exists at initial reservoir conditions and further chooses values of A and B that lead to ( - ) = 5/9 (Pz - Pi). However, on the basis of fracture gradient data, it seems more reasonable to assume values of A and B for consolidated sandstones, limestones and dolomites that give a value of ( - ) = (Pz, - Pi).
P. 340
Decline-Curve Analysis
Authors: Gentry Robert W. 
Published: December 2007

This paper explains a simple and effective method for graphically solving all three types of production decline. The three types of declines are:
exponential hyperbolic, and harmonic.
The mathematical development of these curves was by Arps.
Decline curves are one of the most extensively used forms of data analysis employed in the evaluation of oil properties. Often future production is extrapolated as a straight line on semilog paper (exponential or constant-percentage decline) because this type of decline is the easiest to handle mathematically and graphical. This is done irrespective of the fact that several investigators have reported that this type of decline is rare and that actual oil production usually follows a hyperbolic decline. production usually follows a hyperbolic decline. However, the hyperbolic decline is difficult to analyze mathematically or graphically. The most recent method utilizes transparencies, as proposed by Slider.
The method outlined below greatly simplifies the solution and extrapolation of decline curves. The first four columns of Table 1 list the rate:time and cumulative-production:rate relationships as developed by Arps. The equations are all solutions of the differential equation D = Kq = - (dq/dt)/q. In each instance two unknowns must be calculated from the two relationships. They are the decline exponent n and the initial decline rate Di. The third unknown, qi, can be obtained from the production history of the well. First. the rate:time relationship is manipulated to solve for the value of Dit in terms of the ratio (qi/qt). These relationships are shown in Column 5 of Table 1. Next, the rate:time relationship is solved for Di, and this value of Di is substituted into the cumulative-production:rate relationship. This relationship is then solved for the value of Qt/(qit) in terms of (qi/qt), These relationships are shown in Column 6 of Table 1. Two graphs can then be constructed by selecting a value for n and then substituting values of (qi/qt into the relationships. A curve on each graph for the selected value of n will be produced. This can be done for any desired number of n values from 0 n 1. (See Figs. 1 and 2.) These curves can then be used to analyze and extrapolate decline curves from actual production history.
P. 38
Estimating Drainage Shapes from Reservoir Limit Tests
Authors: Earlougher R.C. 
Published: December 2007

The shape factor for a system can be derived with data from a long-term pressure drawdown test and then can be used to estimate the shape of the drainage region and the location of the well in the system. The calculation technique requires only slope and intercept data from plots of short-term drawdown tests and long-term reservoir limit tests.

Introduction
A long-time pressure drawdown test can be used to estimate the volume being drained by a well. Such a test is normally referred to as a reservoir limit test. All reservoir limit testing techniques use the fact that pressure behavior eventually reaches pseudosteady pressure behavior eventually reaches pseudosteady state for constant-rate drawdown in a closed drainage system. At pseudosteady state, bottom-hole pressure varies linearly with time. The proportionality constant depends on the reservoir volume.
We show how to use pressure drawdown data to estimate both the size and geometry of reservoirs. This requires both transient and pseudosteady-state drawdown data. We present an example to illustrate the procedure. All material given here can be applied to injection-well and gas-system testing when appropriate changes are made.

Analysis Method
When a well in a stabilized reservoir is produced at constant rate, q STB/D, the bottom-hole pressure declines. At early times the pressure is given by
,...................(1)
where
pwf = flowing well pressure, psit = production time, hours-162.6
(2) qBm = ,
(3) kh70 .6 qB 0 .0002637 ktp 1hr = p i - ln kh + 0 .80907 + 2s ,
and
B = formation volume factor, RB/STBct = total system compressibility, psi -1h = formation thickness, ftk = formation permeability, mdpi = stabilized formation pressure, psiq = constant production rate, STB/Drw = wellbore radius, fts = skin factor= fluid viscosity, cp= formation porosity, fraction
m (a negative number) is the slope of the linear part of a plot of pwf vs log t, in psi/cycle. p1hr is the intercept of the straight-line portion of that plot at t = 1 hr. If the pwf (vs log t plot is not linear at one hour, the straight-line portion must be extrapolated to t = 1. p 1 hr is commonly used in transient test analysis to p 1 hr is commonly used in transient test analysis to calculate s.
As the system begins to be affected by boundaries, Eq. 1 no longer applies. After sufficient time the pressure follows pseudosteady-state behavior. pressure follows pseudosteady-state behavior.
JPT
P. 1266
The Use of Capillary Tube Networks in Reservoir Performance Studies: II. Effect of Heterogeneity and Mobility on Miscible Displacement Efficiency
Authors: Simon Ralph , Kelsey F.J. 
Published: December 2007

Abstract
Part II of this series extends the network technique to all miscible displacement mobility ratios and introduces a heterogeneity factor called H. As a result, the network model can be used to study the general miscible displacement case, i.e., miscible displacements with all mobility ratios in linear or areal flow systems having a range of heterogeneities. Engineering charts are presented which show the relationship between recovery, mobility ratio, heterogeneity and pore volumes injected.

Introduction
Part I of this series dealt with equal viscosity, and equal-density miscible displacements. Part II extends the network technique to miscible displacements with all mobility ratios. Part II also introduces a heterogeneity factor, H, used in designing network models. The equal-density limitation is retained. Plug flow is assumed in the capillary tubes. The Plug flow is assumed in the capillary tubes. The original fluid and injected fluid are considered ideal so there are no heat or volumetric effects from mixing. Viscosity of the mixtures is discussed in the section on Calculations.
Part II is divided into three main sections. The first discusses the calculation methods. The second shows comparisons of data calculated by the network technique and data measured for real porous media. These comparisons demonstrate that porous media. These comparisons demonstrate that network models can indeed be used to predict the performance of displacements in real porous media. performance of displacements in real porous media. The third section illustrates the application of network methods to reservoir engineering problems. The illustration is accomplished with a series of charts that relate oil recovery to heterogeneity, mobility ratio, and pore volumes injected for the special cases of a linear system (length/width = 3/1) and five-spots.
Solutions to the Three-Phase Buckley-Leverett Problem
Authors: Guzman Rafael E. , Fayers F. John 
Published: December 2007

Abstract
This paper presents method of characteristics (MOC) solutions to the three-phase Buckley-Leverett problem with and without gravity, for the three classes of equations described by Guzmán and Fayers (1997).12 Thus, solutions for equations with single and multiple umbilic points, and mixed elliptic and hyperbolic equations are constructed. A close relation between the mathematical properties of the equations (in terms of location and quantity of umbilic points) and the physics of flow is described. This relationship can be observed by the effect of gravity on the efficiency of the displacement, the formation of oil and water banks, and the presence of a unique or infinite solution paths within the three-phase flow region for a class of solutions. Elliptic regions did not generate physically inadmissible effects and stable shocks with saturations on opposite sides of elliptic regions were constructed in all the cases examined.
A Compositional Model for CO2 Floods Including CO2 Solubility in Water
Authors: Chang Yih-Bor , Coats B. K. , Nolen J. S. 
Published: December 2007

Summary
This paper presents a three-dimensional, three-phase compositional model for simulating CO2 flooding, including CO2 solubility in water. In this model, CO2 is allowed to dissolve in the aqueous phase, while all other components, except water, exist in the oil and gas phases. Oil- and gas-phase densities and fugacities are modeled by a cubic equation of state. The aqueous phase properties are functions of the amount of dissolved CO2.CO2 solubility is computed using a CO2 fugacity coefficient table that is converted internally from input CO2 solubility data as a function of pressure at reservoir temperature. Correlations for computing the solubility of CO2 in water and other properties of CO2-saturated water are presented. The results for simulation runs with and without CO2 solubility in water are shown for comparison.
ALWORKS - An Artificial Lift Surveillance Tool
Authors: Burleson G. L. , Redden J. D. 
Published: December 2007

Summary
More effective use of computing tools for production surveillance by operations and engineering personnel is critical to increases in profitability. Exxon's Artificial Lift Workstation (ALWORKS) is a software package that allows easy access to electronically stored data and provides that data to various surveillance, analysis, and design applications with minimal user effort. Operations personnel have field-tested the software, and they have noted significant increases in productivity that will lead to increases in profitability.
Pulse Testing: Mathematical Analysis and Experimental Verification
Authors: Odeh A.S. , McMillen J.M. 
Published: December 2007

Abstract
This paper covers theoretical research on pulse propagation in linear cores saturated with air, and propagation in linear cores saturated with air, and discusses bow pulse tests in these systems can be analyzed to provide a measure of the porosity and permeability of the porous medium. It also covers permeability of the porous medium. It also covers experimental work designed to compare these properties, as calculated from pulse-test data, with properties, as calculated from pulse-test data, with those determined by conventional measurements. The paper shows that, when such pulse data are analyzed correctly, the comparison is very favorable; i.e., permeability values vary no more than 3 percent and porosity values no more than 0.5 percent. We conclude that pulse experiments with linear cores saturated with air give data, which when analyzed by methods based on the diffusion equation, give permeability and porosity values comparable with permeability and porosity values comparable with those obtained by conventional methods.

Introduction
Pulse testing is a recently developed method for evaluating reservoir storage capacity and fluid transmissibility. Papers have described the basic theory, based on the diffusion equation, and techniques of pulse testing as applied to field operations. Although some of the papers describe field applications, none report laboratory experimental investigations of pulse testing. This paper covers experimental and theoretical research on pulse propagation through porous media. It tests the adequacy of the use of the diffusion equation as a basis for interpreting pulse-test data.
Using the diffusion equation, the theory of pulse propagation in a linear porous system and a method propagation in a linear porous system and a method of interpreting the experimental data are derived. A few experiments conducted on long Berea cores saturated with air are described. The porosity and permeability values were determined by gas expansion permeability values were determined by gas expansion and steady-state flow, respectively, and the values were compared with those theoretically calculated from experimental pulse data. The comparison shows that the values determined by the conventional methods compare well with those calculated from the pulse data.
Evaluation and Economical Feasibility of Polymer-Assisted Surfactant Flooding for the Gullfaks Field, Norway
Authors: Maldal Trygve , Gilje Eimund , Kristensen Reidar , Kårstad Terje , Nordbotten Atle , Schilling B. E. R. , Vikane Olav 
Published: December 2007

SummaryThis paper presents parts of the work performed to develop and qualify a polymer-assisted surfactant flooding (PASF) system for economical use in the Gullfaks Field, Norway. The paper addresses experimental work done in the laboratory, numerical simulation of PASF, and the evaluation of the potential for PASF in full-field scale.The experimental part comprises core-flooding experiments at different temperatures, pressures, and gas/oil ratios (GOR) to optimize the PASF system for the Gullfaks Brent formation conditions. The surfactant in the PASF system is a branched sulphonate (5,000 ppm) and xanthan (500 ppm). The surfactant-polymer slug is followed by a slug of xanthan (500 ppm) for mobility control. No cosolvent is used. In coreflood experiments more than 70% of the waterflood residual oil was recovered.Using reservoir simulation, a suitable pilot area was found in the Brent reservoir. Additional results from simulations were the amount of chemicals, the time needed for the pilot test, and additional oil recovery.Much effort was put into estimating the full field PASF potential. First, the areas of the field where PASF possibly could be used were selected. Key factors were existing and planned well locations, production data, and long-term production forecasts. Then, the amount of chemicals needed and the expected technical efficiency for each area were calculated. To verify these calculations, an area of the field containing two possible injection wells and three producers was selected for a simulation study. This area was considered the most promising area for PASF.The main conclusion from this work is that, with the present crude-oil price and chemical costs, the PASF process is not economically attractive for use in the Gullfaks field, mainly because the residual oil was considerably lower than believed at project start.