bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hydraulic Programs for Maximum Hydraulic Horsepower and Impact Force on the Rock Surface of the Hole Bottom in Jet Drilling
Authors: Zhang Shao-Huai , Yao Cai-Yin 
Published: December 2007

Summary
In this paper, empirical formulations have been developed to calculate, from full-scale experimental results, the hydraulic horsepower and impact force at the rock surface. Two new hydraulic programs were established to optimize bit hydraulics on the rock surface of the hole bottom. The new theory and methods, when tested in oilfield drilling practice, have increased rate of penetration (ROP) and reduced drilling cost.
Temperature and Common Ion Effects on Effective Acid Penetration in a Fracture
Authors: Ren Shu-Quan , Xiong Hong-Jie 
Published: December 2007

Summary
The effective acid penetration distance, an important parameter in acid-fracturing-treatment design, has a great influence on the effectiveness of the treatment. The temperature in a fracture and the acid/rock reaction products simultaneously affect the acid penetration greatly. But until now, no information concerning this aspect has been published.
To satisfy practical calculation requirements in the treatment design, this paper develops a new mathematical model for the reaction of acid flowing in the fracture by considering the principal factors impacting the effective penetration of the acid. This model was combined with the model of temperature distribution in a fracture, the model of velocity field, and the model of acid/rock surface reaction kinetics to give a simultaneous solution, and a corresponding computer program was developed to perform the calculation. By analyzing and correlating figures and tables of data on the influences of common ion effect, acid concentration, formation temperature, and heat generated by the acid/rock reaction on effective acid penetration distance have been obtained.
The computer program and conclusions in this paper can be used in practical acid-fracturing-treatment design.
Problems Relating to the Fracturing of Deep Wells in the North China Region
Authors: Li Guo-Cal , Zhu Zhao-Ming 
Published: December 2007

SummaryThe oil and gas fields of the Tertiary Sand formation in north China are of complicated structure. The permeability of the pay zone ranges from 0.1 to 50 md, and the porosity approaches 13%. During development, hydraulic fracturing is necessary to stimulate well productivity to achieve satisfactory economic benefit. This paper discusses fracturing fluids and solid leakoff additives, proppants and types of propping, fracture height and diverting fractures, and fracturing pressure for the formation in this area.
Study of Pressure Attenuation of a Submerged, Nonfree Jet and a Method of Calculation for Bottomhole Hydraulic Parameters
Authors: Shen Zhonghou , Sun Qingxiao 
Published: December 2007

Summary
The pressure attenuation of a submerged, nonfree jet has been studied with a simulated wellbore. Equations describing pressure attenuation along the centerline and the cross-sectional pressure distribution of the jet are given. With these equations, bottomhole hydraulic parameters can then be calculated. Also, an optimal design of a jet-drilling hydraulic program based on bottomhole parameters has been developed.
Scaling Laws for Laboratory Flow Models of Oil Reservoirs
Authors: Perkins F.M. , Collins R.E. 
Published: December 2007

Abstract
Publications concerning laws for laboratory flow models of oil reservoirs indicate that the relative permeability and capillary pressure relations must be the same functions of saturation in the model and its prototype. In this paper, the relative permeabilities and saturations are redefined in a way which permits one to have different relative permeability and capillary pressure relations in the model and prototype. The development of the new scaling criteria is demonstrated by deriving scaling laws for one simple flow problem.

Introduction
The successful application of information gathered through bench-scale model studies to the prediction of multi-phase fluid flow behavior in petroleum reservoirs requires careful consideration of the scaling criteria. The requirements which must be met for a small-scale model to duplicate the behavior of a much larger reservoir prototype have been discussed by Leverett, et al, Rapoport, and Geertsma, et al. According to these authors, the relative permeabilities to water, oil and gas and the dimensionless capillary pressures must be the must have the same values in the model and prototype. Furthermore, they point out that the viscosity ratios must have the same values in the model and prototype. In addition to these requirements, other scaling criteria are given which, when considered, usually dictate a much higher permeability in the model than exists in the reservoir.
Since the more permeable model sands may have connate-water and residual oil saturations quite different from those in the prototype, the scaling requirements pertaining to the dependence of relative permeabilities and dimensionless capillary pressures on saturation usually are not met. Also, if the model fluids are selected to give equal viscosity ratios in the model and prototype, one may find greatly different mobility ratios in the two cases and, therefore, may expect grossly different flow patterns. For this reason, Craig, et al, correlated the results of their model studies with mobility ratio rather than with viscosity ratio. As yet, however, no satisfactory method has been advanced which permits use of anything other than the scaling requirements outlined in the previously mentioned papers.
The purpose of this paper is to present a method of developing a set of scaling criteria which permits different relationships between saturation and relative permeability or capillary pressure in the model and prototype. Rather than attempt to report scaling criteria for a variety of practical situations, this paper demonstrates by use of one simple example how the modified scaling criteria are derived.
A Wireline Completion Technique for Sand Control
Authors: Lanmon C.P. 
Published: December 2007

Abstract
A new wireline technique provides fast, economical and sand-free completions in zones noted for sand-production problems. On a single trip in the well, the wireline sand consolidation tool perforates the casing with two holes ]and squeezes consolidating plastic into the formation. The entire operation is performed in 3 hours or less, and the well can immediately be put on production through the treated perforations. One or two pairs of treated perforations are usually adequate for allowable production.
Introduction
The purpose of any sand consolidation treatment is to convert the loose sand behind the casing into a strong. permeable, synthetic sandstone filter. This filter allows fluid production into the casing but prevents surrounding formation sands from flowing. The filter is formed by injecting plastic into the formation. The plastic cements the sand grains together, but still provides interconnecting pore spaces to permit free flow of fluid. By its very nature, the consolidated formation sand makes a filter perfectly sized to keep the unconsolidated sand from filtering through. When treating a well by conventional sand consolidating methods, up to several hundred gallons of treating fluids are pumped through multiple perforations into the formation. This is usually done by pumping the treating fluid from the surface through the tubing. With the wireline technique, 4 1/2 gal of treating fluid contained in the wireline tool are injected directly into perforations made by the tool. There is no opportunity for contamination of the plastic. Each perforation is treated independently. This provides good assurance that each perforation will receive plastic and that none will go untreated. The 4 1/2 gal of treating fluid consolidate a sphere roughly 18 in. in diameter adjacent to the perforations. This consolidated mass has a compressive strength of at least 1,000 psi and retains 60 to 75 percent of the sand permeability. production is from perforations made with this tool. No additional perforating is done. Experience has shown that high production rates can be obtained through these perforations.
Description of Tool
A new wireline tool was designed for this service. The external appearance of the tool resembles a wireline formation tester (Fig. 1). It has two main parts: the mechanical section and the treat section. The mechanical section contains the internal hydraulic system to set the tool in the casing and to operate the control valves. It also contains the perforating gun block. The treat section consists of a pressure amplifier and chambers which contain the fluids to be injected. In operation. two doughnut-shaped packers are forced against the casing by the back-up shoe. The packers prevent contamination of the plastic or loss to the wellbore during injection. Two shaped charges are located in the packer section. one behind each packer. After a seal is effected between the tool and the pipe, the shaped charges are fired, perforating the casing and thus establishing communication between the tool and the formation.
JPT
P. 741ˆ
Effects of Reservoir Heterogeneity on Chemically Enhanced Oil Recovery
Authors: Gupta Akhil Datta , Pope Gary A. , Sepehrnoori Kamy , Shook Mike 
Published: December 2007

SummaryA three-dimensional (3D), multiphase, multicomponent micellar/polymer flooding simulator has been used to investigate the process performance under different conditions of reservoir heterogeneity (stratifications) and mobility ratios. The significance of crossflow has been studied by relating chemical flood recoveries to the effective length-to-thickness ratio and the transverse dispersion number of the reservoir. A long-standing question in micellar/polymer flooding concerns whether small, high-concentration chemical slugs are preferred to large lower-concentration slugs. This aspect of slug size vs. slug concentration has been studied in 3D in the presence of heterogeneity. Finally, chromatographic separation of surfactant and alcohol has been investigated and discussed. It is found that a salinity gradient can be tailored to minimize this separation tendency and that this in fact is the single most important factor, even when compared with adsorption and partitioning. This is a highly favorable result that can and should be exploited to improve the practical design of micellar/polymer floods.
Detailed Simulation of Unstable Processes in Miscible Flooding
Authors: Christie M. A. , Bond D. J. 
Published: December 2007

SummaryThis paper describes applications of linear and nonlinear simulations to unstable miscible flooding. The first section describes a method of calculating linear growth of unstable modes by use of finite differences in the direction of flow and Fourier decomposition perpendicular to flow. This work extends the previous long- and short-wavelength analytic results to cover the whole wave-number range. Results obtained are used to help validate a two-dimensional (2D) code to study nonlinear evolution of viscous fingers and to identify likely fingering regimes in the computed solution by identifying the range of wave numbers that dominates the linear growth behavior. The second section describes the numerical scheme for calculations on a fine grid of the nonlinear development of an instability. Results are presented on calculations of nonlinear growth at several mobility ratios and levels of diffusion. Comparisons with Blackwell's experimental data are presented. Good agreement is obtained, suggesting that the physical processes governing fingering are being correctly modeled.
Use of Dispersion Relationships To Model Adverse-Mobility-Ratio Miscible Displacements
Authors: Young Larry C. 
Published: December 2007

Summary
Improved predictions of petroleum reservoir performance are needed to reduce the risks associated with field-scale miscible flooding. A major shortcoming of established prediction techniques is their failure to model accurately the effects of mobility ratio and viscous fingering on volumetric sweep and displacement efficiency. This paper establishes the feasibility of using physical dispersion relationships to account for fluid mixing associated with viscous fingering. The dispersion relationships use an additional parameter to incorporate a dependence on the local viscosity gradient. Adverse viscosity gradients increase mixing, while favorable viscosity gradients decrease mixing. The dispersion relationships reduce to the normal form when no viscosity gradients are present. The dispersion parameter needed is determined with published data for flow in a long, sandstone core system. Once established, the dispersion relationships are used to predict the performance of a much more complex displacement of reservoir oil by CO2. The simulations reproduce all the salient features observed experimentally and establish the validity of the approach. In particular, the effect of system length is modeled correctly.
An Empirical Model for Microemulsion Phase Behavior
Authors: Robertson Steven D. 
Published: December 2007

Summary
An empirical model for microemulsion phase behavior has been developed that is based on proper choice of pseudocomponents. Previous attempts to represent phase behavior of surfactant/oil/brine systems with three pseudocomponents have been unsuccessful. One of the problems has been salt fractionation between the microemulsion and excess water phases. It was found that through the use of a sulfonate/water pseudocomponent, this effect could be handled, and the system then exhibited true ternary behavior. When this pseudocomponent was used, a single set of Vo/VS and Vw/Vs-vs.-salinity curves was found to be valid for a wide range of overall compositions. These solubilization-parameter curves were fit with empirical equations, and it is these that comprise the model. The basis for a sulfonate/water pseudocomponent is discussed using electrical double-layer theory. In addition, solubilization-parameter curves generated from spherical microemulsion models are compared with the experimental curves.
Well Interference
Authors: Warren J.E. , Hartsock J.H. 
Published: December 2007

Abstract
An asymptotic solution to the equation that describes the flow of a slightly compressible fluid in an infinite porous medium has been used to estimate the interaction between two adjacent wells producing from a common reservoir. A direct method for approximating the interference time defined by Stevens and Thodos has been suggested. An alternative definition for the time of interference, based on the minimum pressure change in the interference region, has been proposed; also, a direct method of determination has been prescribed. Examples have been employed to illustrate the use of both methods.

Introduction
The pressure behavior associated with a completely penetrating well in a uniformly thick, homogeneous, horizontal reservoir containing a single, slightly compressible, mobile fluid is described by the radial form of the diffusion equation. A useful asymptotic solution to this equation is the continuous line-source solution obtained from the basic formulation of Lord Kelvin.
..................(1)
In the derivation of Eq. 1, it is assumed that a well of infinitesimal radius is producing at a constant rate from an infinite reservoir. Because of the assumption of a vanishing well radius, the solution is valid only for large values of time. Horner discusses the limitations on the use of this equation; Elkins presents field data which support Horner's conclusions. If two or more wells are producing from the same reservoir, the resulting pressure distribution is obtained by the superposition of the solutions for the individual wells.
The object of this paper is to develop approximate techniques for determining the time and the place at which pressure disturbances originating from two adjacent wells begin to interact, or interfere, significantly. Two distinct approaches will be followed. First, the effect due to each well will be considered separately; then, the cumulative effect of the two wells will be examined.
A Method for Predicting Oxygen and Air Fireflooding Performance
Authors: Kumar Mridul , Garon A. M. 
Published: December 2007

Summary
This paper presents a simplified procedure for predicting oxygen and air fireflooding performance. Results indicate that oxygen injection may substantially increase oil productivity so that projects may be completed more rapidly in productivity-limited reservoirs. However, oxygen/oil ratio (OOR), or cost per barrel of produced oil, is also higher with oxygen injection. Wet combustion may reduce OOR, especially for oxygen injection and high-pressure reservoirs.
Phase Equilibria in the SACROC Oil/CO2 System
Authors: Chaback J. J. , Williams M. L. 
Published: December 2007

Summary
Phase-equilibrium measurements on SACROC oil/CO2 mixtures show this system to display liquid/vapor (L/V) criticality at a composition of 60 mol% CO2 with a pressure of 2,560 psia [17.65 MPa] and a temperature of 131°F [328.15 K]. In the vicinity of the critical region, liquid quality lines show three- and four-fold pressure multiplicities for a given composition. These multiplicities are a consequence of two effects: (1) the solvent power of supercritical CO2 to extract liquid-phase hydrocarbons at pressures below the saturation pressures of the overall mixtures and (2) the sensitivity of the L/V phase distribution to changes in pressure when the saturation pressure of the overall mixture is in the vicinity of its critical point.
On a CO2-free basis, retrograde liquid produced by flashing C02-enriched reservoir oil at 3,000 psia and 131°F [20.68 MPa and 328.15 K] was found to be similar in composition to other west Texas oils. Under conditions of repeated CO2 contact, this retrograde liquid was found to revaporize like other west Texas oils.
Calculation of Minimum Miscibility Pressure
Authors: Luks Kraemer D. , Turek Edward A. , Baker Lee E. 
Published: December 2007

Summary
An algorithm is presented for the calculation of the thermodynamic minimum miscibility pressure (TMMP) consistent with an equation-of-state (EOS) -based fluid description. This algorithm handles both condensing and vaporizing miscibility mechanisms. TMMP calculations are included for a ternary mixture of pure components, as well as a reservoir-oil/CO2 system.
A Study of Displacement Efficiency in the Redwater Field
Authors: Willmon G.J. 
Published: December 2007

WILLMON, G.J., IMPERIAL OIL LTD., EDMONTON, ALTA., CANADA

Abstract
The Redwater field, Alberta, Canada, discovered by imperial Oil Ltd. in 1948, has now produced approximately 25 percent of the oil originally in place. The present position of the oil-water contact in this strong bottom-water drive pool has been interpreted from borehole contact measurements in observation wells and from an analysis of producing well behavior. Based on this information, and material balance calculations of water influx, the displacement efficiency of the encroaching water is 64 percent. This value has been confirmed by a study of the residual oil and connate water saturations of the two principal rock types in the reservoir. Connate water saturations above the present oil-water contact and residual oil saturations in the water-invaded region were measured directly in cores obtained from the reservoir. in this operation we used a low-invasion, oil-base coring fluid especially developed to minimize flushing of the core by mud filtrate, with a pressure-retaining core barrel to prevent loss of fluids due to depressuring as the core was brought to the surface. Connate water saturations were also determined from conventional oil-base cores and from restored-state capillary pressure tests run at reservoir temperature using reservoir fluids.

Introduction
The Redwater field (Fig. 1) which is located 35 miles northeast of the City of Edmonton in Alberta, Canada, was discovered in 1948. Development was rapid and by the end of 1951 over 900 wells had been drilled on 40-acre spacing. Most of these wells were completed openhole and generally had productivities in excess of 1,000 B/D following a small acid treatment. Production in Redwater is from the reefal Leduc limestone formation of the Woodbend group which is Upper Devonian in age. The Redwater reef covers an area of some 200,000 acres, but only the eastern or updip portion is productive. This part of the reef may be generally divided into three sections: a fore-reef zone, a biohermal zone in the center of the reef and a back-reef zone (Fig. 2). The fore-reef consists of two types of porosity: a zone of infilled clastics which has poor granular and chalky porosity, and a fragmental zone which has good granular porosity. The algal-biohermal zone has vuggy porosity while the back-reef zone has vuggy as well as some granular and chalky porosity. A detailed geological study of the core material from wells that penetrated the reef section through to the oil-water contact shows that 76 percent of the reservoir is composed of vuggy material which contains 60 percent of the total pore space. The remaining granular material contains 40 percent of the total pore volume.
JPT
P. 449ˆ
Effect of Pressure and Temperature on the Phase Behavior of Microemulsions
Authors: Skauge Arne , Fotland Per 
Published: December 2007

Summary
The optimal salinity of three different anionic microemulsions was found to increase as a function of increased hydrostatic pressure. This is equivalent to a phase transition from an upper [Winsor II(+) (WII+)] microemulsion to a lower [Winsor II(-) (WII-)] microemulsion. Increased pressure induces a compressibility effect that is consistent with the observed phase transition. Increasing temperature also leads to increasing optimal salinity. Prediction of temperature effects is complicated by temperature-dependent interactions and entropic contributions caused by dispersion. Fluid models that account for temperature effects are needed; therefore, no attempt was made to develop a theoretical interpretation of this effect. The temperature range is 0 to 100°C, and the pressure was varied from 0.1 to 50 MPa.
Strategy for Alkaline/Polymer Flood Design With Berea and Reservoir-Rock Corefloods
Authors: Potts D. E. , Kuehne D. L. 
Published: December 2007

Summary
This paper discusses the differences between fired Berea and reservoir-rock corefloods using an alkaline/polymer chemical system to recover an acidic California oil. Integrating Berea and reservoir-rock results was necessary in this study because of a limited supply of reservoir core material. Berea corefloods were adequate for initial screening and comparing different injection strategies but gave unrealistically high tertiary oil recoveries.
Both sodium/hydrogen and sodium/calcium ion exchanges were higher in reservoir rock than in Berea. Higher alkali concentrations were required in the reservoir cores to prevent chromatographic separation of alkali and polymer. Excessive exchange of hardness ions was a major cause of lower oil recovery in reservoir corefloods. Recovery improved dramatically when extensive preflushing was used to remove hardness.
Modeling of Three-Phase Liquid/Liquid Equilibria
Authors: Negahban Shahln , Paul Wlllhlte G. , Walas S. M. 
Published: December 2007

Summary
This paper describes a model developed from thermodynamic principles for correlating phase behavior of two-and three-phase systems. The model is based on the representation of excess Gibbs energy with the UNIQUAC equation. A set of computational algorithms is described for estimating the UNIQUAC model parameters from regression of the equilibrium phase data and for predicting phase behavior throughout the entire composition range. The model has been tested for ternary systems and a pseudoternary system. Agreement between the measured and predicted data was excellent for most systems studied. The model was able to match the ternary phase behavior of two- and three-liquid-phase systems that have not been previously simulated. For ternary systems, the estimated UNIQUAC parameters from correlation of the three-phase tie-triangle data describe the phase behavior in both two- and three-phase regions.