bluuebunny/crossref_metadata_2025 huggingface dataset:
Selective Flotation of Casing From a Floating Vessel
Authors: Rae G. , Williams H. , Hamilton J.
Published: December 2007

This paper outlines a new technique for running production casing from semisubmersible drilling rigs on highly deviated wells that was used for the first time on the Captain field, United Kingdom Continental Shelf (UKCS), operated by ChevronTexaco. The process, which incorporates selective-flotation techniques in which air at atmospheric pressure is trapped in the bottom of the casing string to lighten the casing during deployment in the high-angle part of a highly deviated well, has been used successfully on four subsea wells to date. This is believed to be the first implementation of this technique on semisubmersible rigs.
Productivity Changes in Reservoirs With Stress-Dependent Permeability
Authors: Raghavan R. , Chin L. Y.
Published: December 2007

The goal of this paper is to present correlations to permit engineers to evaluate productivity losses in reservoirs with stress-dependent permeability (stress-sensitive reservoirs). The correlations developed in this study are intended to be used in determining production forecasts. For stress-sensitive reservoirs, the reduction in permeability caused by the change in the stress state during production (if any) may significantly reduce expected productivity. It is the purpose of this paper to address methods to ascertain changes in productivity as a result of stress-dependent permeability. A rigorous mathematical model that couples geomechanical and fluid-flow aspects is used to correlate productivity reductions with time. The reduction in the productivity index (PI) is quantified by a skin factor and is expressed as a function of operating variables such as overburden stress, mechanical properties, wellbore pressure, and drainage area. The expressions developed in this study may be incorporated directly (after tuning) in simulators to properly account for changes in productivity.
Improved Quantification of Fit-for-Purpose Saturation Exponents
Authors: Worthington Paul F.
Published: December 2007

Saturation exponent is a key input parameter to those petrophysical algorithms that are used for the evaluation of water saturation Sw. A longstanding problem is that different interpretative algorithms often deliver different predictions of Sw in the same reservoir rock, especially where the reservoir shows shale effects. This problem is overcome by determining a fit-for-purpose saturation exponent, which is specific not only to a given core sample but also to a particular interpretative algorithm for the evaluation of Sw.By using fit-for-purpose saturation exponents and published type algorithms for the petrophysical evaluation of Sw, it is shown that the discrepancies between predicted water saturations obtained using different interpretative equations can be confined to a highly restricted range. Through this process, the sensitivity associated with the choice of a petrophysical model for the evaluation of Sw is demonstrably contained.

This concept is extended to take account of the degree of maturity of the core database. Four expanding data scenarios are enacted to derive data-specific values of the fit-for-purpose saturation exponent using the best-performing type algorithms. The first scenario assumes no core data beyond measurements of Sw and resistivity index using simulated formation water; results are erratic. Scenario 2 draws additionally on a measurement of porosity for each desaturated core plug; it sets the intrinsic porosity exponent m* = 2. Values of Sw predicted using saturation exponents established through Scenario 2 compare closely with those evaluations generated through more-data-intensive scenarios. Therefore, Scenario 2 is proposed as the most efficient way of deriving a fit-for-purpose saturation exponent and thence of obtaining a meaningful evaluation of Sw. A specific type algorithm has been identified for doing this most effectively.

The method has been validated against benchmarks from a public database. The predictive performance of the preferred type algorithm for evaluating Sw through Scenario 2 matches even a fully comprehensive shaly-sand approach with all its additional characterizing data. Therefore, the use of fit-for-purpose saturation exponents allows data needs to be optimized alongside the further containment of uncertainty in integrated reservoir description. Thus, both costs and risk can be reduced simultaneously.
Physically Scaled Model Studies Simulating the Displacement of Residual Oil by Miscible Fluids
Authors: Doscher Todd M. , Gharib Siavash
Published: December 2007

The displacement of waterflood residual oil by a solvent drive has been studied with scaled physical models of a line drive. This work was a first step in an overall study of the displacement of residual oil by CO2. Some results of the subsequent study are presented for comparison.

The usefulness and limitations of scaled physical models for studying the behavior of solvent displacement is analyzed, and it is concluded that such models are very useful for elaborating the mechanism of such a recovery process. Also, because the results obtained with such models correspond with field results, we believe that certain factors, which of necessityhave been neglected in the scaling, play only a minor role in the performance of the process.

When the displacement of the mobile water by the solvent is very stable, the residual oil is produced after a large fraction of the moveable water has been first produced. There is very little evidence of an oil bank being developed, with virtually all the residual oil being produced in solution with the displacing fluid. When the displacement of the mobile water by the solvent is inefficient, because of gravity and/or viscous instability, both the residual oil and solvent begin to be produced much earlier. The recovery of the residual oil parallels the recovery of the mobile water just as in the case of the stable displacement. The efficiency of residual-oil recovery (volumes of oil produced per volume of injected solvent) is much higher at low recoveries when there is marked instability, but with increasing recovery this advantage is lost.

This study concludes that the efficiency of CO2 to recover residual crude oil is influenced primarily by gravity and viscous instabilities resulting from CO2's low density and viscosity in comparison to water. It does not appear that CO2 is any more efficient, in terms of reservoir volumes, than a hydrocarbon-miscible solvent.
Gas-Flow Simulation in Discrete Fracture-Network Models
Authors: Basquet Rémy , Jeannin Laurent , Lange Arnaud , Bourbiaux Bernard , Sarda Sylvain
Published: December 2007

Advanced characterization methodologies are now able to provide realistic pictures of fracture networks. We recently developed software to simulate the transient and pseudosteady-state flows of a slightly compressible fluid in discrete fracture-network (DFN) models. This simulator is used to validate the fracture-network geometry and to calibrate the hydraulic properties of the fractures through dynamic data obtained from flowmeters, interference, and well tests. This paper is dedicated to the extension of the methodology to gas cases, taking into account the high fluid compressibility and the non-Darcy flow effects near the wellbore.

The main features of our simulator are described and illustrated through demonstrative examples. Our DFN simulation approach is based on an optimized explicit representation for both matrix and fracture media and a specific treatment for matrix/fracture and matrix/matrix exchanges. A pseudopressure function is included in the diffusivity equation to take into account highly compressible fluids. The hydrodynamic behavior of gas fluid flow near the wellbore is taken into account through a skin effect proportional to the flow rate for both matrix/well and fracture/well transmissivities.

This innovative numerical simulator is validated against existing analytical solutions and compared with finite-volume solutions computed with a suitable grid. Then, for application purposes, a complex realistic case involving a multiscale natural fracture network with small-scale fractures and major objects such as seismic and subseismic faults is presented. An interference test is simulated on a representative DFN model and on the equivalent dual-porosity model built thanks to upscaling procedures. This upscaled reservoir model is shown to remain consistent with the geological DFN model in terms of gas flow. This example illustrates the practical use of DFN models in our fractured-reservoir-modeling workflow.
The Geometry of a Large-Scale Nitrogen Gas Hydraulic Fracture Formed in Devonian Shale: An Example of Fracture Mapping With Tiltmeters
Authors: Evans Keith , Holzhausen Gary , Wood D. M.
Published: December 2007

Ground deformations occurring around a well undergoing hydraulic fracturing stimulation are analyzed to obtain a description of the geometry and the development of the resulting fracture. Significant upward and lateral growth of a near-vertical fracture aligned with the proposed direction of maximum tectonic compression is inferred to take place initially. However, after six-tenths of the nitrogen gas fracturing fluid had been injected, fracture growth in a horizontal plane abruptly began, and vertical growth ceased. No indication of this breakout is evident in the wellhead pressure or flow rate records. The state of stress in the vicinity of the well is estimated, and implications of the inferred fracture development behavior are discussed.
Simulation of Hydraulic Fracturing in Low-Permeability Reservoirs
Authors: Settari A. , Price H. S.
Published: December 2007

Computer-based numerical simulation can be used as a tool for analysis of fracturing treatments and prediction of postfracturing well performance. The physical problem studied involves fracture mechanics, fluid flow, and heat transfer both in the fracture and in the reservoir. The numerical model predicts fracture extension, length, and width; proppant transport and settlement; fracture closure; cleanup; and postfracturing performance under different producing conditions.

The number of physical features that are customarily neglected in fracture designs have been incorporated in the present model. These include stress-sensitive reservoir properties, proper two-phase calculation of leakoff and cleanup, stress-dependent fracture permeability and temperature- and time-dependent fracturing fluid rheology.

The utility and a priori predictive capability of the model is illustrated with two examples of fracturing jobs. The first example is a marginal gas well stimulated by a medium-size gelled-water fracturing job. The second example is a massive foam fracture in the Elm worth basin. In both cases, the simulator predicted results that are in good agreement with the observed productivity.
Effects of Various Parameters on Hydraulic Fracturing Geometry
Authors: Hanson Merle E. , Shaffer Ronald J. , Anderson Gordon D.
Published: December 2007

We are conducting a theoretical and experimental program on the hydraulic fracturing process. One primary objective of the program is to determine those reservoir properties or characteristics that can control the created fracture geometry. Theoretical models are applied to analyze some aspects of the dynamics of fracturing near material interfaces. The results of these calculations indicate that variation of material properties across a well-bonded interface can cause dynamic material response resulting from the fracturing, which could enhance propagation across the interface. Effects of friction also are analyzed theoretically; however, in the frictional calculations, the wave mechanics are ignored. These calculations show that frictional slip along the interface tends to draw a pressurized fracture toward the interface; this motion tends to reduce the chances of penetrating the material across the frictional interface.

Small-scale laboratory experiments are performed to study the effects of frictional characteristics on hydraulic fracture growth across unbonded interfaces in rocks. Various lubricants and mechanical preparations of the interface surfaces are used to vary the coefficients of friction on the interface surfaces. It is found that the frictional shear stress that the interface surface can support determines whether a hydraulically driven crack will cross the interface. Experiments also are being performed to study the effects of pre-existing cracks, which perpendicularly intersect the unbonded interface, on hydraulic crack growth across the interface. It also is found that the presence of these pre-existing cracks impedes the propagation of the hydraulic fracture across the interface. The experimental results on the effects of friction on the interface and the effects of pre-existing cracks on hydraulic fracture penetration of interfaces are consistent with the predictions of the numerical model calculations.
Elliptical Flow Equations for Vertically Fractured Gas Wells
Authors: Hale Brent W. , Evers J.F.
Published: December 2007

A set of elliptical equations is developed for use in understanding and evaluating vertically fractured gas wells in low-permeability gas sands. The equations are designed for use with short-term flow tests at either constant-rate or constant-pressure test conditions.

Introduction

Much new Rocky Mountain-area gas is being produced from tight gas sands. These wells often prove uneconomical unless they are fractured hydraulically. After the wells are fractured, testing generally is required to ensure that sustained production will justify the cost of a pipeline connection. Current practice generally involves a flow test ranging from several hours to several days. A corresponding pressure buildup often ranges from a day to a week or more. Using a well test involving hours to forecast many years' performance can be very misleading if not done with care.A basic understanding of elliptical equations can yield a great deal of useful information from short flow and buildup tests. It also helps set limits on what information can and cannot be expected from tests.

Elliptical Equation

The elliptical flow equations result from the basic fluid flow equations in porous media with fracture geometry. The fracture is characterized by the distance it extends from the wellbore. It extends from -Xf to +Xf for a total length of 2Xf. Gas flows from the formation into the fracture and is conducted by the fracture to the wellbore. For an infinite conductivity fracture, the inner boundary is one of uniform pressure along the fracture face. Flow may be either at a constant rate, a constant pressure, or a combination of the two.Three points on a given isobar demonstrate steadystate elliptical geometry. Two points are at a distance of +A and -A from the wellbore. The third is at a distance B from the wellbore (Fig. 1). Conformal mapping with the coordinate transformation w = arcsin (Z) is used to transform the X-Y plane into a U - V plane. The transformed system is linear with known solutions for the given conditions. At the external boundary parallel to the fracture, Ve = A′ = B' = arccosh (A) = arcsinh (B). Rearranging this equation yields Ve = ln (A + B) = -ln (A-B) or A2 - B2 = Xf2. This defines an ellipse. The steady-state isobars are concentric ellipses. A is a major semiaxis. B is a minor semiaxis. In this paper, A and B refer to the external ellipse that defines the drainage area. Axf and Bxf refer to the inner ellipse that is the fracture. Fluid flow occurs along the streamlines that are orthogonal to the ellipses. The driving force is the real gas pseudopressure.

Steady-State Elliptical Flow Equations

Development of steady-state equations will solve few problems but lends to an understanding of unsteady-state problems. The generalized steady-state equation is

(1)

Expressed in X - Y coordinates, the equation is

(2a)

Boundary conditions are

(2b)

JPT

P. 2489^
The Effect of Oil/Brine Ratio on Surfactant Adsorption From Microemulsion
Authors: Meyers K. O. , Salter S. J.
Published: December 2007

Static adsorption measurements of petroleum sulfonates on crushed Bell Creek and Berea cores were made using fluids with the same active surfactant concentration but varying brine/oil mass ratios. The salinity of the brine was chosen such that a significant three-phase region existed in the oil/brine/surfactant/alcohol system. The surfactant adsorption was found to be independent of the structural and compositions differences among the fluids.

A series of oil recovery tests in which middle-phase microemulsions were injected into waterflooded cores also were performed. The cores used in these tests had been treated to remove divalent ions accessible to fluid flow. Microemulsion slugs (1.75 to 146% PV) of equal active surfactant concentration but differing brine/oil mass ratios were injected. The total surfactant retention for this system was also found to be independent of the brine/oil mass ratio.
Multidimensional Numerical Dispersion
Authors: Fanchi John R.
Published: December 2007

Numerical dispersion can cause a smearing of otherwise sharp saturation fronts. The usual methods of estimating the magnitude of the smearing effect in one dimension (1D) are shown to apply in two and three dimensions (2-and 3D) as well. Besides the smearing effect, numerical dispersion affects the finite-difference solution of a multidimensional flow problem by rotating the principal flow axes. A method for determining the importance of the rotation effect is discussed. Numerical illustrations are included.
Control and Prevention of Inter-Zonal Flow
Authors: Bearden W.G. , Spurlock J.W. , Howard G.C.
Published: December 2007

An investigation of the factors affecting the inter-zonal flow of fluids in the casing-wellbore annulus of an oil or gas well is presented. Laboratory tests revealed that failure of the casing-cement bond allows communication of fluid at pressure differentials near 1,000 psi. Perforating with a hollow carrier gun does not shatter or crack the cement sufficiently to allow communication through these cracks and does not seriously affect the casing-cement bond failure pressure. The pressure to cause communication at the casing-cement bond can be increased to 3,000 psi by limiting pipe deformation during cementing and subsequent operations. Communication can be prevented, however, up to pressures sufficient to cause the cement to fail or the casing to collapse, by attaching to the casing a seal ring of deformable rubber molded between two steel flanges. When installed, one flange is attached rigidly to the casing to serve as back-up for the gasket while the other flange is movable. To date, these gasket seal rings have been field-tested in 27 wells. Although communication has been noted in two wells, inter-zonal flow has been prevented in other wells in the same area by installing more seal rings between the communicating zones.

LABORATORY INVESTIGATIONS

The laboratory tests performed in this study were divided into three phases. The first phase consisted of tests to determine if perforating would shatter and crack the cement sheath so severely that communication would occur through the cement itself. The second phase consisted of tests to determine more precisely the cause for the casing-cement bond failure. The third phase consisted of tests to evaluate the effectiveness of various deformable seals attached to the casing in preventing communication.

EFFECT OF PERFORATING

The effect of perforating was investigated in tests performed with apparatus shown on Fig. 1. Cement was poured into the annular space between 5 1/2-in. casing and 8 5/8-in. casing and allowed to cure for 72 hours. The apparatus was then perforated with a hollow carrier gun containing eight duPont 26-A shaped charges. Bull plugs were placed over the perforations in the 8 5/8-in. casing and hydraulic pressure was applied inside the 5 1/2-in. casing. The pressure to cause fluid communication past the cement sheath was observed and termed the "bond failure pressure".Several different cement compositions were included in these tests, the results of which are shown in Table 1.

JPT

P. 579ˆ
Field Tests of Organic Additives for Scale Control at the Salton Sea Geothermal Field
Authors: Harrar J. E. , Locke F. E. , Otto C. H. , Lorensen L. E. , Monaco S. B. , Frey W. P.
Published: December 2007

A pilot-size brine handling system was operated from Magmamax Well 1 in southern California to study the characteristics of siliceous scale deposition and to evaluate the possibility of treating the brine with chemical additives to control scaling. The rates of formation, chemical constitution, and morphology of the scales were examined as functions of temperature, brine salinity, substrate material, and antiscalant additive activity. Potential antiscalant compounds were screened using a silica-precipitation inhibition test at 90°C. The most active classes of compounds were those containing polymeric chains of oxyethylene and polymeric nitrogen compounds that are cationic in character. The best single compound was Corcat P-18™ (Cordova Chemical Co. polyethylene imine; molecular weight ~1,800). This compound had no effect on the scale formed at 220°C but it reduced the rates of scaling at 125 and 90°C by factors of 4 and 18, respectively, and it also functioned as a corrosion inhibitor. The best additive formulation for the brines of the Salton Sea Geothermal field (SSGF) appears to be a mixture of an organic silica-precipitation inhibitor, a small amount of hydrochloric acid, and a phosphonate crystalline deposit inhibitor.
Infill Drilling vs. Tertiary Oil Recovery vs. More Imports (includes associated papers 9737 and 9738 )
Authors: Holm L.W.
Published: December 2007

Introduction

in a recent work and series of letters* to PresidentCarter, U.S. DOE, and major oil companies, A.F.van Everdingen has proposed that infill drilling (withcontinued waterflooding) is a more effective way ofimproving oil recovery than tertiary or enhanced oilrecovery using chemicals such as carbon dioxide, surfactant, polymer, caustic, or inert gases.(Steamflooding and steam huff ‘n’ puff operationsare recognized and currently applied secondary oilrecovery techniques and are not included in thecomparison). Specifically, opinions have beenexpressed and claims made that tertiary recoverymethods are too expensive, too slow in developing, and of questionable utility. A statement in a recentletter** indicated that these tertiary recoverymethods should be discarded in favor of infill drillingand continued waterflooding on high-density wellspacing (20 acres or less).I agree wholeheartedly with the need for continuedand stepped-up infill drilling if it is conducted undergood reservoir engineering practices. I seriously question the wisdom of exclusive or indiscriminateinfill drilling and the delay or abandonment ofapplying enhanced oil recovery methods. Furthermore, there is no basis for the claims that infilldrilling alone will "increase oil recovery by 100% ofthe OIP," "recover at least as much oil as the U.S. already has produced," and "improve productionrates to such an extent that the U.S. almost might beindependent of oil from other countries."(Currentimports exceed 8 million B/D). These overstatementswill not help to achieve goals of more domestic oilproduction and reserves.Infill drilling usually will accelerate the productionof oil from a reservoir because of the decrease inspacing between injector and producer. Because mostreservoirs are heterogeneous (i.e., not all portions ofthe reservoir are connected to one another), infilldrilling can permit production of oil from parts ofthe reservoir that might otherwise be bypassed inwaterfloods with larger well spacing patterns. Suchoil truly would be increased reserves. However, someof that oil is bypassed because water injected into awell does not enter and/or flow in a particular zoneof the reservoir because of excessively low permeability, clay sensitivity, wellbore blockage, relative permeability, etc. Such oil cannot be recovered byinfill drilling alone and may require improved wellcompletion or injection techniques, or it could berecovered slowly but eventually at high water/orratios by the water imbibition mechanism with orwithout the additional wells.

The relative importance and effectiveness of infill drilling(with continued waterflooding) and tertiary/enhanced oilrecovery using chemicals(such as carbon dioxide, surfactants, polymers, caustic, miscible gases, and inert gases) arediscussed. Some results of what has been accomplished by infill drilling and tertiary oil recovery are presentedalong with estimates of the potential of these enhancedoil-recovery techniques.

JPT

P. 1169＾
Phase Equilibria in CO2—Multicomponent Hydrocarbon Systems: Experimental Data and an Improved Prediction Technique
Authors: Turek Edward A. , Metcalfe Robert S. , Yarborough Lyman , Robinson Robert L.
Published: December 2007

Numerical simulation of miscible EOR processes requires calculation of the phase equilibria that exist between solvent and oil over the entire solvent/oil composition range. One calculation approach is to tabulate K-values from experimental data and allow the simulator to access the table when necessary. This approach can lead to erroneous conclusions for CO2 miscible processes if there are insufficient tabulated phase equilibrium data to cover all possible compositions, in particular those cases where three phases exist at some point in the displacement.

This paper presents a different approach to the problem. If a generalized equation of state (EOS) can match experimental data, then it can be used in a reservoir simulator to calculate the phase equilibria necessary for the prediction of fluid compositions, densities, and viscosities during a displacement process. Previous work has shown how a generalized Redlich-Kwong equation can be used to calculate typical hydrocarbon phase behavior relationships that exist in condensate and black oil reservoir systems. The equation parameters have been modified further for use in hydrocarbon/CO2 calculations over a wide range of CO2 concentrations.

Appropriate mixing rules for description of the phase equilibria in CO2/hydrocarbon systems have been developed. Experimental binary vapor/liquid equilibrium (VLE) data have been used to evaluate the constants in the EOS for pure CO2 as well as interaction terms used within the mixing rules. Predictions of phase equilibria then have been made and compared with experimental data for a synthetic multicomponent hydrocarbon/CO2 system and a crude oil/CO2 system.
Simulation of Miscible Displacement in Full-Diameter Carbonate Cores
Authors: Batycky J. P. , Maini B. B. , Fisher D. B.
Published: December 2007

Miscible gas displacement data obtained from full-diameter carbonate reservoir cores have been fitted to a modified miscible flow dispersion-capacitance model. Starting with earlier approaches, we have synthesized an algorithm that provides rapid and accurate determination of the three parameters included in the model: the dispersion coefficient, the flowing fraction of displaceable volume, and the rate constant for mass transfer between flowing and stagnant volumes. Quality of fit is verified with a finite-difference simulation.

The dependencies of the three parameters have been evaluated as functions of the displacement velocity and of the water saturation within four carbonate cores composed of various amounts of matrix, vug, and fracture porosity. Numerical simulation of a composite core made by stacking three of the individual cores has been compared with the experimental data.

For comparison, an analysis of Berea sandstone gas displacement also has been provided. Although the sandstone displays a minor dependence of gas recovery on water saturation, we found that the carbonate cores are strongly affected by water content. Such behavior would not be measurable if small carbonate samples that can reflect only matrix properties were used. This study therefore represents a significant assessment of the dispersion-capacitance model for carbonate cores and its ability to reflect changes in pore interconnectivity that accompany water saturation alteration.
Pressure Dynamics in Wells During Gas Kicks: Part 1 - Component Models and Results
Authors: Hoberock L.L. , Stanbery S.R.
Published: December 2007

This is the second part of a theoretical study of the dynamic pressure and flow behavior of an onshore well containing a gas kick controlled by the driller's method. The main results from this study show that (1) casing pressure profiles under assumed constant bottomhole pressure can be very sensitive to both pump stroke variations and standpipe pressure variations, (2) the pressure time delay from casing choke to standpipe is extremely variable, (3) pressure changes rapidly as the gas begins to exit the choke, and (4) the effects of a sudden adjustment at the choke can be magnified at bottomhole, with the largest magnification occurring after the gas begins to exit the choke.

Introduction

In this paper, the proposed well model described in Part I is developed employing the transmission line solution techniques of Part 1. The final model is operated as a real-time, manually controlled simulator, whose outputs are compared with actual test well data.In Part 1, the development of the digital and analog solution techniques were based on the flow of a Newtonian fluid in a line of constant dross section and length. Thus, to use either of these techniques to represent the drillpipe and annular lines, it is necessary to account for the facts that the drilling mud is actually non-Newtonian and that the annular liquid lines are of time-varying lengths and annular cross section. In addition, to represent the two-phase fluid line, the fact that the fluid within this region is a gas/mud mixture with the gas rising at a velocity relative to the mud must be taken into account. Accordingly, the necessary modification to the basic solution techniques to model these effects and suitable models for the mud pump, casing choke, and drill bit are discussed.

Drillpipe Transmission Line

To account for the change in inner diameter between drillpipe and collars, it is necessary to model the drillpipe as two coupled fluid-line sections. However, in the specific test well installation that is modeled, there are no collar sections in the drillstring. Thus, it can be assumed that the drillstring is a single constant-length section of constant circular cross-sectional area.Within the range of drillpipe velocities encountered in practice, the most commonly used drilling muds frequently are modeled as nonNewtonian Bingham plastics. Accordingly, to use the solution techniques of Part 1 to predict pressure and flow propagation in the drillpipe, it is necessary to make suitable modifications to reflect the nonNewtonian nature of the drilling mud. It can be shown that the steady-state frictional pressure drop per unit length dp/dz for the flow of a Bingham plastic in a smooth circular pipe is given by

(1)

where p = fluid density, D = pipe diameter, U = mean fluid velocity, and f = Fanning friction factor.

Unlike the Newtonian case, however, the Fanning friction factor in Eq. 1 for a Bingham plastic is a function of the Bingham Reynolds number N and the Headstrom number NHe.

JPT

P. 1367^
Applications of Water-Soluble Polymers in the Oil Field
Authors: Chatterji J. , Borchardt J.K.
Published: December 2007

Water-soluble polymers commonly used in the oil field are reviewed. The properties of guar, guar derivatives, cellulose derivatives, xanthan gum, locust bean gum, starches, and synthetic polymers, especially polyacrylamides, are discussed and related to chemical structures of the polymers. Original data comparing polymer solution viscosity properties under identical conditions are presented. These data include effect of polymer concentration on solution viscosity, temperature effect on solution viscosity, viscosity in acidic solution, and polymer solution viscosity in the presence of a hemicellulase enzyme.

Introduction

Water-soluble polymers are used extensively in various phases of drilling, completion, workover, and production of oil and gas wells. 1,2 In spite of widespread use, the connotation "polymers" (macromolecules) still confuses many people involved in oilfield work. This confusion is due in part to the wide variety of commercially available polymers, which are generally organic and have a carbon-based structure. The lack of understanding and appreciation of polymers and their properties severely restricts the selection of the best polymer for the particular application under consideration.

The purpose of this paper is to define clearly the commonly used but often misunderstood terminology. The paper defines the term polymer and distinguishes between homopolymers, copolymers, block copolymers, and graft copolymers. The chemical structures of most commonly used naturally occurring polymers, chemically modified naturally occurring polymers, and synthetic polymers are shown. Attempts are made to describe how physical and chemical properties of these organic polymers are regulated by their chemical structures. Use of these polymers in drilling, cementing, fracturing, acidizing, controlling water production, preventing sand production, clay stabilization, lost circulation, and enhanced recovery, where known, is described.

Polymer Definition

Ethylene gas (CH2=CH2, boiling point˜-152°F, molecular weight=28), under proper chemical conditions, will combine with hundreds or thousands of other ethylene molecules to form a solid product called polyethylene, with a molecular weight in the millions. This polymer is familiar to everyone as packaging film and can be seen at any supermarket meat counter. This conversion of ethylene to polyethylene is called polymerization - the chemical combination of many small molecules to form a very large molecule.3–6

Polymer Definition

Ethylene gas (CH2=CH2, boiling point˜-152°F, molecular weight=28), under proper chemical conditions, will combine with hundreds or thousands of other ethylene molecules to form a solid product called polyethylene, with a molecular weight in the millions. This polymer is familiar to everyone as packaging film and can be seen at any supermarket meat counter. This conversion of ethylene to polyethylene is called polymerization - the chemical combination of many small molecules to form a very large molecule.3–6
Linear Waterflood Behavior and End Effects in Water-Wet Porous Media
Authors: Kyte J.R. , Rapoport L.A.
Published: December 2007

Introduction

Theory indicates that linear waterfloods should exhibit scaling and stabilization properties in both oil-wet and water-wet porous media. Experimental verification of these properties in oil-wet media was obtained some time ago, and more recently, Perkins employing a high permeability unconsolidated sand and a low oil-to-water viscosity ratio, has obtained flooding data in a water-wet medium which follow the pattern of scaling and stabilization. Also, Root and Calhoun have found similar trends in the displacement of gas by liquids from unconsolidated sands. In general, however, the experimental evidence appears still somewhat conflicting since scaling and stabilization of water floods in water-wet media has not been observed in most of the studies to date.

The purpose of this paper is to provide a more comprehensive picture of waterflood behavior in water wet media and to corroborate the validity of the scaling and stabilization concepts. The need for differentiating between the intrinsic nature of water-oil displacements inside a porous medium and perturbating secondary end effects is discussed, pertinent experimental procedures are outlined and the results of flooding tests conducted at low and at high oil-to-water viscosity ratios on consolidated, water-wet Alundum cores are analyzed.
Influence of Polymer-Molecule/Wall Interactions on Mobility Control
Authors: Duda J. L. , Klaus E. E. , Fan S. K.
Published: December 2007

This paper presents the results of a study of molecule/wall interactions on permeability modification of consolidated porous media by polymer solutions. The experiments were conducted with a newly developed low-shear porous media viscometer. This is a simple-to-use, versatile instrument that is particularly useful for measurements at the low shear rates characteristic of reservoir flooding. The key for obtaining reproducible, steadystate results was to expose the porous medium to several hundred pore volumes of polymer solution to saturate it with polymer. The effective permeability during polymer flow and the residual permeability were determined for xanthan gum and polyacrylamide solutions in Berea sandstone, Bradford sandstone, filter papers, and Nuclepore® filters. A mechanistic interpretation of the coupling of adsorption, mechanical entrapment, shear rate, and inaccessible pore volume effects on the effective and residual permeabilities was developed. This is the first study to show that inaccessible pore volume can influence the residual permeability significantly.
Compositional Modeling With an Equation of State
Authors: Nghiem L. X. , Fong D. K. , Aziz K.
Published: December 2007

This paper describes an implicit-pressure explicit-composition and explicit-saturation compositional model. The model uses an equation of state (Peng-Robinson) for phase equilibrium and density calculations. Interfacial tension effects are considered also. The formulation of the pressure equation yields a symmetric and diagonally dominant matrix that allows the use of the iterative conjugate gradient method for large systems. Simulation of laboratory CO2 displacements shows good agreement between calculated and experimental results. The influence of interfacial tension is investigated. Physically reasonable results also have been obtained for hypothetical areal and cross-sectional problems.
Microemulsion Phase Behavior-Observations, Thermodynamic Essentials, Mathematical Simulation
Authors: Bennett Karl E. , Phelps Craig H. K. , Davis H. Ted , Scriven L. E.
Published: December 2007

The phase behavior of microemulsions of brine, hydrocarbon, alcohol, and a pure alkyl aryl sulfonate—sodium 4-(1 -heptylnonyl)benzenesulfonate (SHBS or Texas 1)—was investigated as a function of the concentration of salt (NaCl, MgCl2, or CaCl2), the hydrocarbon (n-alkanes, octane to hexadecane), the alcohol (butyl and amyl isomers), the concentration of surfactant, and temperature. The phase behavior mimics that of similar systems with the commercial surfactant Witco TRS 10-80™. The phase volumes follow published trends, though with exceptions.

A mathematical framework is presented for modeling phase behavior in a manner consistent with the thermodynamically required critical tie lines and plait point progressions from the critical endpoints. Hand's scheme for modeling binodals and Pope and Nelson's approach to modeling the evolution of the surfactant-rich third phase are extended to satisfy these requirements.

An examination of model-generated progressions of ternary phase diagrams enhances understanding of the experimental data and reveals correlations of relative phase volumes (volume uptakes) with location of the mixing point (overall composition) relative to the height of the three-phase region and the locations of the critical tie lines (critical endpoints and conjugate phases). The correlations account, on thermodynamic grounds, for cases in which the surfactant is present in more than one phase or the phase volumes change discontinuously, both cases being observed in the experimental study.
Studies on Pilot Water Flooding
Authors: Rosenbaum M.J. Fischer , Matthews C.S.
Published: December 2007

The purpose of this work was to learn what in formation could be obtained from various types of pilot water floods and to attempt to find the optimum pilot pattern for a reservoir which had previously been depleted by a solution gas drive. The study was made in the laboratory with mathematical methods, a dynamic analog and a potentiometric analog. Results were tested against the field histories of a number of pilot water floods.

At a reasonable value of cumulative injection, the total production rate for the one-in factor five-spot should reach about 6.5 per cent of injection rate, and for a four-injector five-spot, about 9 per cent. Accurate estimates of ultimate recovery cannot be made on the basis of such small production rates. However, with a pilot composed of nine injectors and 16 producers, the production rate is approximately 50 per cent of injection rate at a reasonable value of cumulative injection. Some information for extended performance predictions high be obtained from such a large pilot.

These conclusions were drawn on the basis of results obtained for unit mobility ratio, and a study using the potentiometric analog was made of the effect of other mobility ratios to determine the range of applicability of these predictions. For the four-injector, five-spot pilot with Mw, o = 1/4, the ratio of production to injection rate (before water breakthrough) is about twice that for Mw, o = 1; with Mw, o = 4, it is about two-thirds; and with Mw, o = 10, it is about one-third. For high mobility ratios, it was found that the production rate increased considerably as water-cut increased. These results can be used to modify, qualitatively, the interpretations based on curves for the unit mobility ratio cases.

It was found that the maximum ratio of production rate to injection rate observed in field pilot floods was of the same order as that predicted by these methods. The time required to reach this maximum did not generally agree with the time predicted for a homogeneous reservoir. The difference between predicted and observed time of response gives an indication of the permeability profile and of the condition of the producing wells.
An Improved Summation-of-Fluids Porosity Technique
Authors: Hensel W. M.
Published: December 2007

The summation-of-fluids porosity technique is used widely throughout industry. While its primary value is associated with fast turnaround time for core data required for well control during drilling, the data frequently are used for reserves estimates, general reservoir engineering, and geological purposes. This paper describes an improved technique that provides a more precise determination of "pore water" to the exclusion of clay water, water of hydration, etc. This, in turn, can improve the accuracy of porosities and associated oil and water saturation values when expressed as fractions of the pore volume. The method determines the pore water at a stabilized furnace temperature of 350° F (177°C), which is below the thermal degradation temperature of common clays and minerals associated with most reservoir rocks, gypsum being a common exception. Case histories are shown where use of the 350°F (177°C) stabilized temperature method resulted in marked improvement in agreement of porosity data determined by Boyle's law and summation-of-fluids methods where previous lack of agreement existed using standard API procedures for measuring pore-water volumes.
Unified Analysis of Drawdown and Buildup Data for Physical Model Reservoir Flow With Producing Well at Center of Vertical Fracture
Authors: Jaggernauth D. J. , Lin Z. S. , Lescarboura J. A. , Bishop K. A. , Clark C. R. , Swift G. W.
Published: December 2007

A physical model of a gas reservoir having a vertical fracture with fracture half-length xf = 0.0635 m was developed. The model is a right circular cylinder of latex concrete with the radius xe = 0.305 m so that the xe/xf ratio is 4.8. The producing well is located at the center of the fracture. Experimental drawdown and buildup data taken from this reservoir were analyzed using available theoretical developments from the literature. The effect of pressure on permeability (the Klinkenberg effect) was included in the analysis. Simplex optimization was used in conjunction with unified (drawdown plus buildup) super-positioning to give fracture half-lengths of 0.0631 and 0.0635 m from two sets of experimental data. Corresponding values for permeability for these two sets of data were 0.0605 × 10−18 and 0.0624 × 10−18 m2, respectively, at a Klinkenberg coefficient of 5900 kPa. The fracture half-length and permeability are shown to be highly correlated. Thus, the results have more uncertainty than would be found in determining parameters by similar methods of analysis for an unfractured system. Bearing this in mind, the agreement between the known fracture half-length and values determined from the analysis of experimental data is excellent. Thus, we have demonstrated the utility of unified analysis as well as the ability to create an artificial fracture. Since the location of the model fracture relative to producing and observation wells is at the discretion of the designer, our model presents a unique opportunity to study various configurations which might be difficult to handle by mathematical modeling alone.
Interpreting Relative Permeability and Wettability From Unsteady-State Displacement Measurements
Authors: Batycky J. P. , McCaffery F. G. , Hodgins P. K. , Fisher D. B.
Published: December 2007

A procedure has been developed and tested for evaluating the capillary pressure and wetting properties of rock/fluid systems from unsteady-state displacement data such as that used for calculating two-phase relative permeability characteristics. Currently, the common practice is to conduct most coreflooding experiments so that the capillary pressure gradient in the direction of flow is small compared with the imposed pressure gradient. The proposed method, on the other hand, is based on performing low rate displacements during which capillary forces and, hence, end effects can influence the saturation distribution and pressure response of the core sample. Besides providing a means for monitoring capillary forces and wettability during the dynamic displacement test, the proposed method has the advantage of permitting the displacement tests to be conducted at rates more typical of those in the reservoir. Thus, it is possible to avoid potential problems such as fines migration and emulsion formation, and the method permits a realistic representation of transient interfacial effects that can be important with reservoir fluid systems and chemical flooding agents.

Specifically, the method involves performing low rate displacements between the irreducible-water and residual-oil endpoint saturations. Except for the added provision of stopping, restarting, and sometimes reversing the flow after the endpoints have been reached, these are routine unsteady-state displacements in which the standard pressure drop is measured external to the core between the inlet and outlet fluid streams. The dynamically measured capillary pressure properties – besides indicating strong, weak, intermediate, or mixed wettability – then can be used to derive relative permeabilities from the displacement data. Examples of the – technique for determining wettability are given for pure-fluids/Berea-sandstone and reservoir-fluids/preserved-reservoir-rock systems.