bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Analytical Scaling Method for Spontaneous Imbibition in Gas/Water/Rock Systems
Authors: Li Kewen , Horne Roland N. 
Published: December 2007

Summary
A method was developed to scale the experimental data of spontaneous water imbibition (cocurrent) for gas/water/rock systems. In this method, a dimensionless time was defined with the effects of relative permeability, wettability, and gravity included. The definition was not empirical but based on a theoretical derivation. Using this dimensionless time, experimental data from spontaneous water imbibition in different rocks with different size, porosity, permeability, initial water saturation, interfacial tension, and wettability might be scaled. The scaling model proposed in this study for gas/water/rock systems was verified experimentally for different rocks (Berea, chalk, and graywacke from The Geysers) with significantly different properties; it was also verified experimentally at different initial water saturations in the same rock. The scaling results from this study demonstrated that the cocurrent spontaneous water imbibition in gas/water/rock systems could be scaled and predicted.
Quantification of Displacement Mechanisms in Multicomponent Gasfloods
Authors: Johns R. T. , Yuan H. , Dindoruk B. 
Published: December 2007

SummaryLocal displacement efficiency in gasfloods depends strongly on the minimum miscibility pressure (MMP) or minimum miscibility enrichment (MME). The values for these design parameters depend in turn on the displacement mechanisms: vaporizing, condensing, or a combination of the two known as a condensing/vaporizing (CV) drive. Characterization of the displacement mechanism, however, is currently limited to these broad categories, with little reference to the degree to which a CV displacement is condensing or vaporizing. This "discrete" classification approach can result in significant confusion in the interpretation and comparison of various miscible gasfloods. The focus of this paper, therefore, is to present a method to quantify in a continuous way the fraction of a multicomponent gasflood that is vaporizing or condensing as the pressure or gas enrichment is increased.The approach relies on finding key tie lines for a dispersionfree 1D displacement using method of characteristic theory (MOC). We quantify the displacement mechanism for any number of oil or gas components by calculating the displacement path lengths along ruled surfaces bounded by these key tie lines. We show how to determine the displacement mechanism along each of these ruled surfaces by the calculation and comparison of the key tie-line lengths. Several multicomponent fluid characterizations are considered, including a 12-component enriched-gasflood and a 13-component CO2 flood.The results show that as the pressure or enrichment is increased, condensation occurs at the expense of vaporization. We also show by numerical simulations that the sensitivity of the local displacement efficiency to dispersion depends on the condensing fraction of the displacement. We show that the trends in displacement efficiency sensitivity to dispersion oppose previously published results, which showed that vaporizing displacements are more sensitive to dispersion than condensing ones. The differing trends are likely the result of improper and discrete determination of the displacement mechanism.
Visualization of Oil Recovery by Water-Alternating-Gas Injection Using High-Pressure Micromodels
Authors: Sohrabi M. , Tehrani D. H. , Danesh A. , Henderson G. D. 
Published: December 2007

Summary
The use of WAG (water-altemating-gas) injection can potentially lead to improved oil recovery from the fields. However, there is still an incomplete understanding of the pore-scale physics of the WAG processes and how these lead to improved oil recovery. Simulating the three-phase flow for prediction of the WAG performance in oil reservoirs is an extremely complex process. The existing three-phase relative permeabilities used in simulation are very approximate and do not properly account for the effects of fluid interfacial tension and rock wettability. Network model simulators are being developed to enable the prediction of three-phase relative permeability under different wettability conditions. However, such simulators need to be verified against experimental observations. In this paper, we present experimental results and discussion of a series of capillary-dominated WAG tests carried out in glass micromodels with wettability conditions ranging from water-wet to mixed-wet and oil-wet. Pore level fluid distribution and flow mechanisms were studied, and fluid saturation, at different stages of the experiments, were measured. The results showed that, under any of the wettability conditions, oil recovery by alternating injection of WAG was higher than water or gas injection alone. WAG recovery was observed to be higher for the oil-wet model than that in the mixed-wet one, which in turn was higher than that in the water-wet micromodel. Given enough time and more cycles of WAG injection, the recovery of the mixed-wet model seems to catch up with that of the oil-wet model.
Phase Behavior Studies of Two Model Surfactant Systems
Authors: Benton William J. , Natoli John , Qutubuddin Syed , Mukherjee Surajit , Miller Clarence A. , Fort Tomlinson 
Published: December 2007

Abstract
Phase behavior studies were carried out for two systems containing pure surfactants but exhibiting behavior similar to that of commercial petroleum sulfonates. One system contained the isomerically pure surfactant sodium-8-phenyl-n-hexadecyl-n-sulfonate (Texas 1). The other contained sodium dodecyl sulfate (SDS). Additional components used in both systems were various pure short-chain alcohols, NaCl brine and n-decane. Aqueous solutions containing surfactant, cosurfactant, and NaCl were studied over a wide range of compositions with polarizing and modulation contrast microscopy as well as the polarized light screening technique. Viscosity measurements were conducted on selected scans of the Texas 1 system. Maxima and minima of the scans were correlated with textural changes observed with microscopy. The aqueous solutions were contacted with equal volumes of n-decane, and phase behavior and interfacial tensions were determined. The middle microemulsion phase was found to be oil continuous close to the upper phase boundary and water continuous close to the lower phase boundary. Both the Texas 1 and SDS systems showed similar behavior in that the middle microemulsion phase was observed over the entire range of surfactant concentrations studied.
Phase Boundaries of Microemulsion Systems as a Way of Characterizing Hydrocarbon Mixtures
Authors: Shah Kishor D. , Green Don W. , Michnick Michael J. , Willhite G. Paul , Terry Ronald E. 
Published: December 2007

Abstract
Phase behavior of microemulsions composed of TRS 10-80, brine (10.6 mg/g NaCl), isopropyl alcohol, and mixtures of pure hydrocarbons was studied to determine the location of phase boundaries of the single-phase microemulsion region. Studies were conducted on pseudoternary phase diagrams where the pseudocomponents were isopropanol, brine, and a constant ratio of surfactant to hydrocarbon (S/H). Phase boundaries were determined by the titration method developed by Bowcott and Schulman,1 which was extended to systems of interest for oil recovery by Dominguez et al.2,3
The titration method involves the addition of brine to a single-phase microemulsion until phase separation occurs. Then the system is titrated to transparency by addition of isopropanol. Dominguez et al.2,3 demonstrated the applicability of the titration method for systems containing pure alkanes. They found upper and lower phase boundaries (high and low alcohol concentrations) for the microemulsion regions on S/H pseudoternary diagrams that were represented by linear relationships between the volume of alcohol and the volume of brine required to attain a single-phase microemulsion. This region, termed Region 4, bounded by linear phase boundaries, extends over a wide range of brine concentrations including regions of interest to enhanced oil-recovery processes.
The research reported in this paper extends the work of Dominguez et al.2,3 to mixtures of pure hydrocarbons. The locations of the lower phase boundaries for Region 4 were determined for four types of mixtures prepared with pure hydrocarbons ranging from C6 to C18.
In all phase behavior experiments, the lower phase boundary of Region 4 was a straight line when volume of alcohol was plotted against volume of brine. Furthermore, the slope of this phase boundary was found to be a linear function of alkane carbon number (ACN) for pure hydrocarbons and equivalent alkane carbon number (EACN) for mixtures of pure hydrocarbons.
The correlation of a property of the phase diagram (the slope of the lower phase boundary) with EACN suggests a new approach to characterization of hydrocarbon/surfactant systems. In our experience, the EACN determined from phase behavior studies is more reproducible than the EACN determined from methods involving measurements of interfacial tensions. This method has potential for characterization of surfactant/hydrocarbon systems for complex mixtures of hydrocarbons, including crude oils.
Toward an Accurate and Efficient Chemical Model for Hydrothermal Brines
Authors: Weare John H. , Harvie Charles E. , Møller-Weare Nancy 
Published: December 2007

Abstract
In this paper, we describe the development of a chemical equilibrium model for hydrothermal waters based on the semiempirical equations of aqueous electrolyte solutions recently introduced by Pitzer et al.1 We discuss application of this model to the system, Na/K/Ca/Mg/Cl/SO4/ H2O, at 25°C. Accurate solubility predictions (usually within 5 % of experimental results) can be made for ionic strengths of 0 to 20 m. Comparison with experimental data indicates that a theory parameterized by binary and ternary data can be used to predict solubilities accurately in much more complex mixtures. Mineral solubilities calculated with this model are compared with those calculated from models based on ion pairing. Whereas our predictions are typically within 5 %, the ion pairing models are substantially in error even at low ionic strengths.
We are extending our chemical equilibrium programs to include high temperature (T ≃ 200°C). We have assessed the availability of data for modeling hydrothermal waters. In this paper, we discuss the accuracy of existing high temperature data in terms of the binary HCl/H2O system. Our results indicate that below about 150°C, there may be a sufficiently accurate data base to parameterize a hydrothermal water model including all commonly occurring ions. Above 150°C, the data may not be reliable, and appropriate data should be collected for certain key systems.
Evaluation of the Low Tension Flood Process for High-Salinity Reservoirs—Laboratory Investigation Under Reservoir Conditions
Authors: Murtada Hani , Marx Claus 
Published: December 2007

Abstract
In northwest Germany, oil reservoirs are characterized by high-salinity brines with up to 23% TDS. For such salinity conditions, fatty alcohol derivatives with 4.5 ethene oxide (EO) units were found to lower the inter-facial tension (IFT) drastically and to mobilize residual oil almost completely.
Intensive flood experiments under reservoir conditions with the use of sandpacks 2 m in length allowed optimizing the low-tension process for an oil field that was considered a possible candidate. A combination of surfactant slug followed by a tailored mobility buffer showed best results in terms of additional oil recovery and process duration. A preflush of low-concentration aqueous polymer solution brought a decisive further increase in additional oil recovery.
Results obtained for the slug process indicated that variables such as IFT, surfactant concentration, flooding velocity, and pressure gradient influence the low-tension process in a combined manner.
Oil produced in the oil bank showed alteration in properties, compared with the oil used to saturate the pore space.
Characterization of Petroleum Sulfonates by a Nonaqueous Titration Method
Authors: Voss Kim R. , Bricker Clark E. , Michnick M. J. , Willhite G. P. 
Published: December 2007

Abstract
A new method is described for the determination of the equivalent weight for petroleum sulfonates. The method is based on the direct acidimetric titration of the sulfonate in acetic acid/acetic anhydride solvent using a titrant of perchloric acid in dioxane. From the titration, the moles of perchloric acid required to react with the sulfonate is measured. The equivalent weight is calculated from the grams of sample titrated and the moles of acid used. The potentiometric titration can be carried out in less than 10 minutes and can be done with 10 to 100 mg of sample.
The accuracy and precision of the procedure were examined by the titration of sodium salts of p-toluene sulfonate, 2-naphthalene sulfonate, and petroleum sulfonates. In general, values for the equivalent weight were within 2% of those values determined by the Epton titration, by wet ashing methods, or from the theoretical value. The relative standard deviation (RSD) for the procedure is estimated to be 0.5%. For p-toluene sulfonate, an RSD of 0.15% was calculated.
The new method was used to determine the equivalent weights for three fractions of a petroleum sulfonate obtained by the preferential elution from silica gel with alcohol. A series of samples with varying equivalent weight was prepared by proportional combination of the three fractions. Analysis by high-performance liquid chromatography (HPLC) gave a set of data points of peak areas for the series. A plot of equivalent weight as a function of disulfonate to total peak area ratio resulted in a straight line. The slope of this line is descriptive of the molecular weight range for the petroleum sulfonate.
Laboratory Evaluation of Prospective Enriched Gas-Drive Projects
Authors: Kehn D.M. , Pyndus G.T. , Gaskell M.H. 
Published: December 2007

Introduction
Much attention has been given in the past few years to methods of increasing the recovery of oil from proven reserves. Numerous laboratories have made investigations to evaluate the possibilities of increased oil recovery by high-pressure injection of dry gas, injection of a propane slug followed by dry gas, solvent flooding, and by the injection at relatively low pressures of gases enriched with ethane and propane. Several years ago, Whorton and Kieschnick published the results of laboratory studies on high-pressure gas injection which showed that, in the case of light oils, recoveries could be considerably increased by sweeping the reservoir with dry gas at pressures in excess of 3,000 psig. The increase was attributed by those authors to the vaporization of oil at the invading gas front and viscosity and solubility effects produced at the front by the invading gas.
Later, Stone and Crump presented the results of a series of displacement experiments in which a light undersaturated crude oil was displaced from sand-packed columns with unusually high recoveries when the displacing gas was a rich condensate or a dry gas enriched with ethane or propane. They also conducted similar experiments at higher pressure on heavy undersaturated crude oil, although in this case the increase in recovery was not as great as in the case of the light oils. In both cases, viscosity reduction and swelling of the by-passed oil behind the invading gas front were believed to be responsible for the more favorable recovery of the original oil in place.
Within the past year, other investigators have presented the results of laboratory studies of miscible slug and solvent flooding recovery processes. This paper describes the laboratory methods developed for evaluating benefits to be obtained by enriched gas drive in specific reservoirs, and presents the results of several displacements of crude oils which possess a wide range of physical properties. The displacements were conducted at reservoir conditions of temperature and pressure.
Force Coefficients From Wave Project I and II Data Including Free Surface Effects
Authors: Dean Robert G. , Dalrymple Robert A. , Hudspeth Robert T. 
Published: December 2007

Abstract
Wave force data, obtained by Chevron Oil Field Research Co. in conjunction with Shell Development Co. and Exxon Production Research Co.. have been reanalyzed for drag and inertia coefficients. These data are the field results of Wave Projects I and II and consist of water surface elevations and forces on piles of various sizes at different elevations within the water column. The analysis here is based on the stream function wave theory and Morison's equation, resulting in drag (CD) and inertia (CM) coefficients including a dependency on Reynolds number. Principal findings are a somewhat higher value for CD at large Reynolds numbers than that obtained by Aagaard and Dean.1 Free surface effects include a run-up on the piling and an associated local modification in drag coefficients, resulting in reductions in overall forces and moments. Using a large data set of 349 waves (digitized at 0.1 second), variances between predicted and measured forces also were obtained that followed a normal probability distribution.
Borehole Position Uncertainty - Analysis of Measuring Methods and Derivation of Systematic Error Model
Authors: Wolff C.J.M. , de Wardt J.P. 
Published: December 2007

Summary
This article presents a new model for describing well-position uncertainties. An analysis for surveying position uncertainties. An analysis for surveying errors is given that demonstrates that they are mainlysystematic rather than random. The error model, based on systematic errors, compares well withpractical experience. A graph is presented that shows practical experience. A graph is presented that shows typical lateral position uncertainties of deviated wellsfor various kinds of surveys.

Introduction
During the past 10 years, the uncertainties involvedin determining the true course of a borehole havebecome a cause for concern. The more deviated anddeeper the holes were drilled, the more often were theoperators faced with inexplicable differences betweenvarious surveys made in the same well. As early as 1971, Truex mentioned that possible lateral positionerrors of highly inclined wells could be up to 30 m ata depth of only 2000 m. Two years before that, Walstrom et al. introduced the ellipse-of-uncertainty concept to describe the positionuncertainty, which can be expected with various surveymethods. Experience, however, has shown that theellipse calculated by this random error model isunrealistically small, which is thought to be duemainly to the nature of the statistical error modelused.The essential differences between the existingrandom error model and the model proposed in thisarticle are illustrated by the following simplifiedexample. Consider the straight and inclined part of awell with these directional characteristics: total depthalong hole (AHD or DAH) 2500 m, surveyed at100 stations at 25-m intervals, and all having aninclination of I Delta I = 30 0.5 and an azimuthof A Delta A 90 1.The bottomhole position of this well in north, east, and vertical coordinates easily is found as
N = D AH sin I cos A = 0, E = D AH sin I sin A = 1250 m, andV = D AH cos I = 2165 m.
The position uncertainty of the bottom of thiswell, according to the error model presented in thisarticle, follows straightforwardly from theassumption that the measuring errors at all 100 stations havethe same magnitude (they are correlated fully).Hence, by simple trigonometry, as sketched in Fig. 1,
and
In the random error model, however, it is assumedthat the measuring errors vary randomly from onestation to another, which gives them a tendency tocompensate one another. This randomness of themeasuring errors causes the position uncertainty tobe smaller than the former values - in our example, by a factor equal to the square root of the number ofmeasuring stations, which is 100 = 10.
JPT
P. 2339
Rock Mechanics, Petrophysics, and Stratigraphy of the Tuscaloosa Trend
Authors: Traugott Martin O. 
Published: December 2007

Summary
Tough drilling and evaluation problems fall to easy solutions in deep Tuscaloosa wells: Log resistivities in soft shales are linked to impending pore pressure reversals in deep sands; high-resistivity hard shales are linked to lost circulation intervals; and resistivity invasion profiles are linked to freshwater anomalies in boreholes with oil mud.

Introduction
Several onerous things can happen during the 150 or 180 days it takes to drill a deep Tuscaloosa well in south Louisiana. As an example, consider this scenario: A Tuscaloosa well penetrates the over pressured Chalk formation. The well kicks and subsequently loses returns. The operator sets protective casing and drills ahead into the Eagleford shale. Gas in the mud increases. He sets a liner, drills into the Massive Tuscaloosa, loses returns, and reduces mud weight. Drilling continues. The well penetrates the Interbedded Tuscaloosa and kicks hard. Pipe sticks. The well is sidetracked. Apparent pay zones are tested and flow fresh water. The depth is 18,000 ft (5500 m). The cost: $5 million. But things are not so tough if casing and evaluation programs are based on geomechanical and petrophysical concepts. Understanding this depends on understanding four basic ideas:Formations can be grouped into one of two classifications-soft or hard-based on resistivity logs.Soft (viscoelastic) shales often have high fracture gradients and high pore pressures depending on proximity to massive sands. (Pore pressures can be derived from resistivity logs.)Hard shales (and carbonates) often have lower pore pressures and lower fracture gradients depending on boundary conditions.Fresh water often occurs in isolated, lower-pressure sands, near high-pressure zones containing salt water.
Stratigraphy and Shale Resistivity
The Tuscaloosa wells penetrate several different stratigraphic units, some hard and some soft (Fig. 1). An outline is given here of the important intervals:

Het Lime
A hard carbonate and potential lost-circulation zone.

Claiborne Group
A soft shale interbedded with limes and sands. Not over-pressured except where the Wilcox sands are not developed.

Wilcox
A sand interbedded with hard, resistive shales. Not developed at the east edge of the trend.

Midway
A semisoft shale. Shale resistivity is 2 to 3 Omega typical depths, and fracture gradients are high based on breakdown tests.

Clayton
A thin, soft, over pressured shale. Pore pressures increase with depth as a function of distance from the lower Cretaceous shelf margin (Fig. 2).

Chalk
A thick carbonate that often is drilled underbalanced.

Eagleford
A thick, soft, often over pressured shale.
JPT
P. 428^
Hydraulic Fracture Geometry: Fracture Containment in Layered Formations
Authors: van Eekelen H. A. M. 
Published: December 2007

AbstractOne of the main problems in hydraulic fracturing technology is the prediction of fracture height. In particular, the question of what constitutes a barrier to vertical fracture propagation is crucial to the success of field operations.An analysis of hydraulic fracture containment effects has been performed. The main conclusion is that in most cases the fracture will penetrate into the layers adjoining the pay zone, the depth of penetration being determined by the differences in stiffness and in horizontal in-situ stress between the pay zone and the adjoining layers. For the case of a stiffness contrast, an estimate of the penetration depth is given.
Buckling Behavior of Well Tubing: The Packer Effect
Authors: Mitchell R. F. 
Published: December 2007

Abstract
The equilibrium equations for a helically buckled tubing are developed and solved directly. The results show that the packer has a strong influence on the pitch of the helix, and that the pitch developed by the helix is different from the pitch calculated by conventional methods. In addition, the solution provides (1) shear loads and bending moments at the packer and (2) constraining force exerted on the tubing by the exterior casing. This last result can be used to estimate friction effects on tubing buckling.