bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mechanism of Alcohol Displacement of Oil from Porous Media
Authors: Taber J.J. , Kamath I.S.K. , Reed Ronald L. 
Published: December 2007

Abstract
Alcohol floods of consolidated sandstone cores have shown the process to be strongly dependent on the phase behavior of the particular alcohol-oil-water system used. This means that in many cases the mechanism does not conform to the idea of a piston-like displacement. Instead, it is found that by changing the alcohol it is possible to change the relative velocities of the oil and water and, in fact, the entire mechanism of the process. The effects of rate, viscosity, initial saturation, distance travelled and hysteresis of relative permeability on the alcohol flooding mechanism are discussed.

Introduction
Reasons for interest in the use of alcohol to miscibly displace oil and water from a porous medium appear in the existing literature. The mechanism of the displacement has been considered and the apparent implications formulated into a theory which presumably would enable one to predict the essential features of the process. Unfortunately, most of the reported experiments have been performed with unconsolidated or artificially consolidated sands. With these systems some of the noteworthy facets of the process are obscured and resulting data appear uncertain.
It is the purpose of this paper to show how the use of consolidated sandstones has led to revision of the mechanism and, hence, the theory of alcohol flooding. The practical result is increased pessimism toward the possibilities of commercial application of the simplest form of the alcohol-slug process. However elucidation of the mechanism has made it possible to define the essential characteristics of a system of slugs which will behave in a nearly piston-like fashion and, thus, yield the best possible result.

Equilibrium Phase Behavior
Fig. 1 is a diagram of the ternary system isopropyl alcohol (IPA)-Soltrol-calcium chloride brine. Brine was used to prevent plugging of the core and calcium chloride was used because sodium chloride brine exhibits a solid phase with Soltrol and IPA. If alcohol is added in increments to the immiscible mixture of water and oil represented by Point A, the path followed by the successively equilibrated samples will be on the Line ABC and pass from the immiscible region to the miscible region by crossing the binodal curve at B. Consider the intersection D of this path with the tie Line EF. The quantity of oleic phase is proportional to the Segment ED and the quantity of the aqueous phase is proportional to DF. Compositions of the two phases are specified by Points E and F. It is clear that in the case shown the oleic phase is diminishing and entirely disappears when miscibility is achieved.
Predicting Multiphase Flow Behavior in a Deviated Well
Authors: Hasan A. Rashid , Kabir C. Shah 
Published: December 2007

Summary
In deviated wells of an offshore producing environment, flow of two-or three-phase mixtures is invariably encountered. While many investigators have studied vertical multiphase flow behavior, few studies, often entirely empirical, deal with deviated well systems. The main objective of this work is to present a model that predicts both flow regime and pressure gradient in a deviated wellbore. In the modeling of flow-pattern transition and void fraction, an approach similar to that for vertical flow is taken; i.e., four principal flow regimes are recognized: bubbly, slug, churn, and annular.
The transition from bubbly to slug flow is found to be at a local void fraction of 0.25. This transition criterion in terms of gas and liquid superficial velocities is found to be significantly affected by the well deviation, particularly in highly deviated wells. The transitions from slug to chum flow and chum to annular flow occur at high fluid velocities and are unaffected by well deviation.
The velocity-profile-distribution parameter for bubbly, slug, and churn flows is found to be unaffected by the well deviation angle. Similarly, the terminal rise velocity for small bubbles also appears to be insignificantly affected by the well deviation. In contrast, the "Taylor" bubble-rise velocity changes dramatically as deviation angle is increased. Thus, the characters of slug and chum flows in a deviated well differ from those in a vertical well.
Data on gas void fraction were obtained both from a 5-in. [127-mm] circular pipe and from annular flow channels for deviation angles up to 32° from the vertical. The validity of the proposed model is demonstrated with these data and with laboratory data from other sources. Several field examples are presented to show the application of the model.
An Imbibition Model - Its Application to Flow Behavior and the Prediction of Oil Recovery
Authors: Naar J. , Henderson J.H. 
Published: December 2007

Introduction
The displacement of a wetting fluid from a porous medium by a non-wetting fluid (drainage) is now reasonably well understood. A complete explanation has yet to be found for the analogous case of a wetting fluid being spontaneously imbibed and the non-wetting phase displaced (imbibition). During the displacement of oil or gas by water in a water-wet sand, the porous medium ordinarily imbibes water. The amount of oil recovered, the cost of recovery and the production history seem then to be controlled mainly by pore geometry. The influence of pore geometry is reflected in drainage and imbibition capillary-pressure curves and relative permeability curves. Relative permeability curves for a particular consolidated sand show that at any given saturation the permeability to oil during imbibition is smaller than during drainage. Low imbibition permeabilities suggest that the non-wetting phase, oil or gas, is gradually trapped by the advancing water.
This paper describes a mathematical image (model) of consolidated porous rock based on the concept of the trapping of the non-wetting phase during the imbibition process. The following items have been derived from the model.A direct relation between the relative permeability characteristics during imbibition and those observed during drainage.A theoretical limit for the fractional amount of oil or gas recoverable by imbibition.An expression for the resistivity index which can be used in connection with the formula for wetting-phase relative permeability to check the consistency of the model.The limits of flow performance for a given rock dictated by complete wetting by either oil or water.The factors controlling oil recovery by imbibition in the presence of free gas.
The complexity of a porous medium is such that drastic simplifications must be introduced to obtain a model amenable to mathematical treatment. Many parameters have been introduced by others in "progressing" from the parallel-capillary model to the randomly interconnected capillary models independently proposed by Wyllie and Gardner and Marshall. To these a further complication must be added since an imbibition model must trap part of the non-wetting phase during imbibition of the wetting phase. Like so many of the previously introduced complications, this fluid-block was introduced to make the model performance fit the observed imbibition flow behavior.
Microbial Flora in a Number of Oilfield Water-Injection Systems
Authors: Carlson V. , Bennett E.O. , Rowe J.A. 
Published: December 2007

Abstract
This report concerns the microbial flora found throughout the surface facilities of six water-injection systems in Texas and Oklahoma. Each system is described in detail and water quality data are presented when available.
Pseudomonads and sulfate-reducers (Desulfovibrio) were the predominate organisms found in the systems. The genera Sphaerotilus, Bacillus, Achromobacter, Micrococcus, Clostridium, Flavobacterium, and Sarcina were also isolated in significant numbers. Molds, iron bacteria, sulfur bacteria and soil bacteria were found less frequently in the systems.
It is concluded that a complex microbiological flora exists in oilfield water-injection systems. A tendency for waters to deteriorate in passage through solid bed filters is also noted.

Introduction
The injection of water into a subsurface formation is often accompanied by numerous problems, the origin and nature of which are only partially understood. During the past few years, investigators have indicated that bacteria are involved in some of these problems even though very little specific information is available concerning this matter.
It is surprising that investigators working on microbiological problems in water injection have never made a complete study of the flora of these systems. The logical course to pursue is that of identifying the microbial flora and then examining each organism individually and in combination with others to determine if they produce a particular problem.
The objective of the present investigation is to identify the microbial flora in water-injection systems. In addition, the quality of the water in most of the systems was determined and some observations made on the extent to which passage through surface-handling facilities affects water quality. The information derived from this study can serve as a foundation for additional basic investigations.
Rheological Properties of Pseudoplastic Fluids in Porous Media
Authors: Gogarty W.B. 
Published: December 2007

Abstract
With flow of non-Newtonian fluids in porous media, effective viscosities are needed for use in the Darcy equation. These viscosities depend on the rock parameters and flowing conditions. In this investigation, rheological and flow results were correlated to develop an expression for calculating effective viscosities. Surfactant-stabilized dispersions of water in hydrocarbon were used with consolidated sandstone cores of different permeabilities. The average shear rate in a core was related to the permeability and porosity of the core and the frontal velocity through the core.
By using the correlation obtained for determining effective viscosity, experimental and theoretical values were compared for each fluid system by determining average and maximum errors. For the fluid system showing the largest average error, the correlation fit 38 experimental points with an average and maximum percentage error of 4.3 and 14.8, respectively. For the fluid system showing the least error, average and maximum percentage errors of 1.8 and 4.3, respectively, were calculated using 29 experimental points.

Introduction
Use of non-Newtonian fluids in the petroleum industry is not new. Fluids of this type have been used for many years as fracturing agents and drilling muds. Recently, attention has focused on the use of high molecular weight polymer solutions for secondary recovery. Results have been reported on studies relating to the flow behavior of polymer solutions in porous media. Each study gives the viscosity in the Darcy equation as a function of the rheological properties of the fluid, the characteristics of the porous medium and the pressure gradient. The functional forms of the reported expressions differ somewhat in each study.
Fundamentals of Oilwell Jet Pumping
Authors: Grupping A. W. , Coppes J. L. R. , Groot J. G. 
Published: December 2007

Summary
This paper explains the theory behind the operation of jet pumps, including the effect of density differences between power fluid and produced fluids. By differentiating between the pump intake pressure and the throat-entrance pressure, we provide insight into the factors that affect jet pump performance. A stepwise procedure is given for sizing and selecting a jet pump.
Effect of Vertical Fractures on Reservoir Behavior-Incompressible Fluid Case
Authors: Prats M. 
Published: December 2007

Abstract
The effect of a sand-filled vertical fracture of limited radial extent and finite capacity (fracture capacity is the product of the permeability and width of the fracture) on the flow behavior of a cylindrical reservoir producing an incompressible fluid through a centrally located well has been investigated mathematically. The shape of the lines of equal pressure near the fracture is essentially independent of the size of the reservoir, provided that the field radius is of the order of the fracture length or larger. For reasonable values of production rates and of fluid, reservoir and fracture properties, the total pressure drop between the end of the fracture and the well is generally negligible compared with the pressure drop in the reservoir. With regard to production response, the effect of vertical fractures can be represented by the production response of an equivalent or effective well radius. For a high-capacity fracture, the effective well radius is a quarter of the total fracture length, decreasing with the fracture capacity. When invasion effects are simulated by decreasing the width of the damaged zone with distance from the well, the effect of formation damage around a fracture on the production response is not so serious as indicated by the literature. This suggests that frac fluids with a conventional filter-loss response are better than high-spurt-loss frac fluids, provided the effective permeability of the damaged zone is the same.

Introduction
This paper considers the effect of the fracture capacity, as well as the formation damage which can result from fracture treatments, on the productive capacity of vertically fractured wells. Other publications, notably those of van Poollen, consider these same effects. In addition to providing more general results for vertical fractures than are available from the literature, the present paper gives the equivalent well radius of fractures having different lengths and Capacities and, also, includes pressure distributions in and around the fractures. The effect of a damaged zone around a fracture on the production response was not found to be so great as that reported by van Poollen. This difference probably stems from the fact that we consider a damaged zone which is widest (but is still small) near the well and thins out toward the extremities of the fracture, whereas van Poollen considers a damaged zone having a uniform width for the entire fracture length. Simple, but adequate, equations which describe the effect of these variables on production response are presented (in Appendixes A and B). Thus, results can easily be extended to values of the variables not specifically considered here.
Flow in Heterogeneous Porous Media
Authors: Warren J.E. , Price H.S. 
Published: December 2007

Abstract
Techniques for studying the performance characteristics of heterogeneous reservoirs have been developed. The effect of permeability variation on both the steady-state and the transient flow of a single fluid has been investigated. Limited comparisons with field and laboratory data have been made.
The physical models studied consist of random three-dimensional arrays of homogeneous porous blocks. The permeabilities of the individual elements are assigned according to a specific distribution function; uniform anisotropy is introduced by varying the relative dimensions of the blocks. A particular model is perturbed simply by re-arranging its elements at random. The behavior of a physical model is determined by digitally solving its numerical analogue.
Based on computational experiments, subject to the restrictions implied by the assumptions that were made, the following general conclusions have been drawn.The most probable behavior of a heterogeneous system approaches that of a homogeneous system with a permeability equal to the geometric mean of the individual permeabilities.The effects of flow geometry and anisotropy on the most probable value of the effective permeability of a heterogeneous medium are finite but not significant.The permeability determined from a pressure build-up curve for a heterogeneous reservoir gives a reasonable value for the effective permeability of the drainage area.A qualitative measure of the degree of heterogeneity and its spatial configuration are obtained from a comparative study of core analysis and pressure build-up data.
It has been indicated that these conclusions are predicated on the assumption that the core analysis and the pressure build-up data represent true reservoir characteristics. Common sources of error in these data have been discussed.

Introduction
One of the most significant problems of reservoir engineering is that of determining the nature and the disposition of the heterogeneities that inevitably occur in petroliferous formations. It is with this problem that this paper is concerned.
Design and Operational Considerations for Unsupported Offshore Pipeline Spans
Authors: Shah B. C. , White C. N. , Rippon I. J. 
Published: December 2007

Summary
Design and operational considerations have been examined in determining the significance of unsupported offshore pipeline spans that may develop during pipeline installation or field operation. Allowable unsupported span lengths determined during design are generally based on strict code compliance and a design foundation encompassing the worst possible environmental and operational loads. During operation, however, unsupported spans develop beyond the allowable limits, perhaps as a result of various unforeseen local conditions. Applying original design criteria is likely to result in cost-prohibitive repair predictions, while lack of action may result in loss of production. Without the design code requirements of an existing or a proposed pipeline system being violated, realistically safe design can be approached through evaluation of the sensitivity of the key design parameters. Priorities for remedial repair of the unsupported spans can be established for the pipelines in service while operating constraints, budget, and schedule are recognized. On the basis of periodic surveys, properly formatted survey data, and reanalysis of the design parameters, pipeline span repair cost estimates and schedules can be appreciably reduced. Similar principles can be applied to a pipeline in planning and design stages to ensure a safe operating design and to eliminate an uneconomically conservative design. These design and operational considerations are illustrated through a case study.
Linear Water Flood with Gravity and Capillary Effects
Authors: Hovanessian S.A. , Fayers F.J. 
Published: December 2007

ABSTRACT
The one-dimensional displacement equation for a homogeneous porous medium, including the effects of gravity and capillary forces, has been solved by a numerical method. A finite-difference scheme is developed for obtaining saturation, pressure and fractional flow profiles in waterflood recovery problems. From the numerical examples given, it is concluded that the gravitational forces have a pronounced effect on the saturation profiles and the pressure distribution curves of the system.

INTRODUCTION
Within the past 20 years, a number of papers have appeared in the literature dealing with the quantitative treatment of water flood recovery problems. In their celebrated paper, Buckley and Leverett described a method for calculating saturation profiles when the effects of capillary pressure and gravity are excluded. Terwilliger, et al, included the effect of gravity in their theoretical and experimental investigation of oil recovery problems and obtained close correlation between experiment and theory. Welge described a simplified method for obtaining the average saturation and the oil recovery from an oil reservoir. The effect of gravity can be included in this calculation.
More recently (1958) Douglas, et al, presented a method for calculating saturation profiles which includes the effect of capillary pressure. The authors start with the one-dimensional displacement equation (which is nonlinear in the derivative) and, by a change of variable, transform this equation to a semi-linear partial differential equation. This equation is then solved by a finite-difference method on a high-speed digital computer. Fayers and Sheldon obtained the solution of the one-dimensional displacement equation by directly replacing the differential equation by a finite-difference equation.
Mechanics of Gravel Placement and Packing: A Design and Evaluation Approach
Authors: Wahlmeier Mark A. , Andrews Phillip W. 
Published: December 2007

SummaryMuch has been written, researched, and applied toward the advancement of improving gravel-packing technology in the past 10 to 15 years. Still, gravel packing is not a routinely successful completion method to control sand production from weakly consolidated formations. One of the principal reasons for this lack of consistency is an incomplete understanding of the mechanisms involved in achieving efficient gravel placement and packing. The objectives of this study are to discuss the fundamentals of liquid/solid transport and to present the structure of a pseudo-three-dimensional (pseudo-3D) mathematical model used for aiding in the design and evaluation of gravel-packing treatments. Also presented is the validation of the mathematical algorithm in comparison to large-scale, high-pressure, deviated physical wellbore studies and actual field case histories.
Effect of Viscosity on Relative Permeability
Authors: Downie J. , Crane F.E. 
Published: December 2007

Introduction
The general application of Darcy's law to natural rocks has already been challenged in the literature. The evidence shows that the permeability as calculated from the Darcy equation can be a function of the pressure drop and the salt concentration of the water phase. Most explanations for aberrant behavior involve clays and their properties and have been qualitatively satisfactory. Recently, however, Odeh revived the theoretical views of Yuster. Since Yuster's concept implies a fundamental error in using Darcy's relationship for two-phase flow, and not merely that conditions may limit its use, Odeh's experimental support arouses considerable interest. However, Odeh's work as presented is thought to be inadequate. He has omitted important information about his materials and procedures; therefore, acceptance of his conclusions should be withheld. Since a clay effect is possible, Odeh should have been allowed space to present a more detailed account of the rocks which he used and the precautions which he took to avoid confounding the effects of clay and fluid circulation. In addition, it follows from Odeh's discussion that the oil relative permeability should increase as the viscosity ratio increases. Odeh presents data corroborating this deduction. It also follows that the oil relative permeability should decrease as the viscosity ratio of oil to water decreases. However, our results show that a high relative permeability, when once attained by using a viscous oil, may be maintained when that oil is replaced by an oil of much lower viscosity.