bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improved Quantification of Fit-for-Purpose Saturation Exponents
Authors: Worthington Paul F. 
Published: December 2007

Summary
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

Abstract
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

Summary
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

Abstract
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

AbstractComputer-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

Abstract
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

Summary
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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＾