bluuebunny/crossref_metadata_2025_split huggingface dataset:
Asymptotic Analytical Solutions for Imbibition Waterfloods in Fractured Reservoirs
Authors: Civan Faruk , Rasmussen Maurice L. 
Published: December 2007

Summary
A generalized methodology is presented that obtains analytical solutions for imbibition waterfloods in naturally fractured oil reservoirs undergoing multistep matrix-to-fracture transfer processes. The phenomenological representation of the oil transfer from matrix to fracture is based on a three-exponential matrix-to-fracture transfer function, the necessity for which is seen by examination of experimental data. The resulting integrodifferential equation is converted to a fourth-order partial differential equation, linearized by invoking the unit endpoint mobility-ratio approximation, and then solved analytically by asymptotic means. It is shown that the asymptotic-approximation approach significantly reduces the complexity of the solution process and yields adequate solutions for long-time evaluation of waterfloods in naturally fractured reservoirs. The solution is not only computationally advantageous, but it also provides a physically meaningful interpretation of the propagation speed and diffusive spreading of the progressing wave front, which could not be readily obtained from the usual type of solution methods, such as the direct application and inversion of the Laplace transformation.
Integration of Partial Differential Equation for Transient Radial Flow of Gas-Condensate Fluids in Porous Structures
Authors: Eilerts C.K. , Sumner E.F. , Potts N.L. 
Published: December 2007

Abstract
The second-order, nonlinear, partial-differential equation representing the transient radial flow of gas-condensate fluids in reservoirs has been integrated by using finite-difference equations and electronic computers. Effect was given to pressure-dependent permeability, viscosity, and compressibility and to distance-dependent permeability. The influence of a second-degree velocity term in the Darcy equation was investigated. Implicit methods were used and practical, convergent solutions were obtained with material balance to less than 6 x 10 for recovery of one-half the reserve at constant flow rate. Integration results provide the productive period of a reservoir for a given constant rate and the fraction of the fluid initially in place that can be recovered in that period. The properties of a lean and a rich fluid are represented in a set of integrations designed to demonstrate the effect of different constant-recovery rates and significant variables emphasized one at a time.
Introduction
A method is needed for computing the availability or reserve of a gas in a formation, making use of all technical and engineering information that is pertinent. As a step in this direction, a program for computing transient linear flow was developed that utilizes principles of earlier finite-difference computing for a similar purpose and gives effect to significant pressure- and distance-dependent properties of reservoirs and their contents. The present paper pertains to transient, radial flow of gas-condensate fluids. In the partial-differential equation of flow, effect is given to the variables viscosity and compressibility, and also to permeability. Included in the study is the quadratic form of the Darcy equation of flow that has been the subject of field tests and that has been applied to a gas with constant properties in transient flow computing. Inclusion in the differential equation of variable coefficients to represent properties greatly complicates the higher derivatives of the equation. Because it was impractical to make a required improvement in certain of the finite-difference derivatives by Taylor-series expansion, five-term derivatives were used in the implicit computing. Related methods were developed that can improve general facility in manipulating finite-difference equations.
BASIC EQUATIONS
PARTIAL DIFFERENTIAL EQUATION
The basic partial differential equation for transient radial flow in the direction of decreasing radius is
(1)
where r radius, Lv = apparent velocity along radius, L/tp = density, M/L3t = time, tphi = porosity, dimensionless.
In this equation, only the porosity is regarded constant. The density is
(2)
where p = pressure, m/LtM = molecular weight of fluid, mT = constant temperature of fluid, Tz(p)= pressure- dependent compressibilityfactor, dimensionlessR = gas constant, mL2/t2T.
SPEJ
P. 141ˆ
Burst-Induced Stresses in Cemented Wellbores
Authors: Fleckenstein W. W. , Eustes A. W. , Miller M. G. 
Published: December 2007

Summary
This paper presents the results of a finite element study of the resistance to burst pressure. Results from the 2D model quantify the effects of various mechanical properties of cement on a cemented wellbore. Comparison of the predicted stresses with experimental results demonstrated that ductile cement is far less likely to crack radially from high internal burst pressures than a brittle cement. It is demonstrated that the in-situ formation stresses acting on the cemented wellbore greatly affect the burst resistance of the cemented wellbore.
The industry acknowledges that there is an increase in the burst resistance of cemented pipe vs. uncemented pipe; but the effects of cement and formation mechanical properties, and in-situ stresses are not well understood. This paper presents the results of a finite element study of the resistance of casing to internal burst pressure under a variety of conditions. This will provide for better design understanding of the stress conditions developed in casing under burst loading.
2D stress-distribution model results are presented in graphical and tabular format for a variety of geometrical and mechanical material properties of formations, cement slurries, and casing combinations.
A better understanding of the true stress profile in cemented pipe allows for less expensive decisions concerning casing design parameters and safety-factor criteria. Applications using the burst resistance of the cemented pipe as a system as opposed to using the burst resistance of free pipe can include deeper drilling with thinnerwalled pipe, smaller rigs, and better casing integrity decisions for refracturing candidates.
Petroleum Reservoir Simulation Coupling Fluid Flow and Geomechanics
Authors: Gutierrez M. , Lewis R. W. , Masters I. 
Published: December 2007

Summary
This paper presents a discussion of the issues related to the interaction between rock deformation and multiphase fluid flow behavior in hydrocarbon reservoirs. Pore-pressure and temperature changes resulting from production and fluid injection can induce rock deformations, which should be accounted for in reservoir modeling. Deformation can affect the permeability and pore compressibility of the reservoir rock. In turn, the pore pressures will vary owing to changes in the pore volume. This paper presents the formulation of Biot's equations for multiphase fluid flow in deformable porous media. Based on this formulation, it is argued that rock deformation and multiphase fluid flow are fully coupled processes that should be accounted for simultaneously, and can only be decoupled for predefined simple loading conditions. In general, it is shown that reservoir simulators neglect or simplify important geomechanical aspects that can impact reservoir productivity. This is attributed to the fact that the only rock mechanical parameter involved in reservoir simulations is pore compressibility. This parameter is shown to be insufficient in representing aspects of rock behavior such as stress-path dependency and dilatancy, which require a full tensorial constitutive relation. Furthermore, the pore-pressure changes caused by the applied loads from nonpay rock and the influence of nonpay rock on reservoir deformability cannot be accounted for simply by adjusting the pore compressibility.
Screening and Coreflood Testing of Gel Foams To Control Excessive Gas Production in Oil Wells
Authors: Wassmuth F. R. , Hodgins L. A. , Schramm L. L. , Kutay S. M. 
Published: December 2007

Summary
Polymer-enhanced foam and gel-foam formulations were screened and tested for their injectability and gas-blocking ability in Berea sandstone cores and carbonate packs (in the presence and absence of oil at 85°C). Gel foams, with suitable gelation delay, were propagated through packed cores in a similar manner as polymer-enhanced foams (PEF's). However, the gas-blocking ability of cured gel foam was far superior to that of PEF. The gel foam blocked gas flow completely, even in the presence of oil, and a significant pressure differential had to be exceeded before the gas could channel through the gel foam and flow through the core.
A General Single-Phase Wellbore/Reservoir Coupling Model for Multilateral Wells
Authors: Ouyang Liang-Biao , Aziz Khalid 
Published: December 2007

SummaryA general single-phase flow model that rigorously couples flow in the reservoir with flow in the wellbore is presented. The model can be applied to a parallelepiped drainage domain consisting of any number of wells containing any number of laterals of arbitrary configurations. The fluid is assumed to be slightly compressible, and gravity head is included. Reservoir inflow for the entire time period (from early transient to late pseudosteady state) is handled in the coupling model by integrating the instantaneous point source/sink solution over both time and space. Pressure drop along any lateral in the well system is the sum of three components: wall friction, gravity, and acceleration owing to wall inflow or outflow. Effects of wall mass transfer on wall friction and kinetic energy change are taken into account.A computer package has been developed and used to perform a series of sensitivity studies that lead to several important and interesting observations. The coupling model may be applied to determine well productivity, well index for multiphase flow simulation, wellbore pressure profile, and wellbore inflow or outflow distribution for any time in the well's production/injection life.
Tenth SPE Comparative Solution Project: A Comparison of Upscaling Techniques
Authors: Christie M. A. , Blunt M. J. 
Published: December 2007

SummaryThis paper presents the results of the 10th SPE Comparative Solution Project on Upscaling. Two problems were chosen. The first problem was a small 2D gas-injection problem, chosen so that the fine grid could be computed easily and both upscaling and pseudoization methods could be used. The second problem was a waterflood of a large geostatistical model, chosen so that it was hard (though not impossible) to compute the true fine-grid solution. Nine participants provided results for one or both problems.
A New Efficient Averaging Technique for Scaleup of Multimillion-Cell Geologic Models
Authors: Li D. , Beckner B. , Kumar A. 
Published: December 2007

Summary
Increased resolution in reservoir characterization is driving the need for efficient and accurate upscaling techniques for reservoir simulation, on which reservoir performance prediction relies. Unfortunately, the existing averaging methods (i.e., harmonic, arithmetic, power law, geometric, or a combination of harmonic and arithmetic methods) are only applicable under the circumstances of perfectly layered or perfectly random heterogeneity distributions, which are rarely seen in realistic reservoir descriptions. This paper presents a new averaging method that improves these upscaling averaging methods for realistic reservoirs and can substitute for the orders-of-magnitude slower direct-simulation methods, such as pressure-solver techniques. The new averaging method first calculates the upper and lower bounds of the effective properties based on the nature of geology and then employs a new correlation, scaling, and rotation technique to estimate the effective properties for the upscaled grid. The approach not only preserves the accuracy of the time-consuming simulation methods but also retains the speed of the traditional averaging methods.
Five real sandstone and carbonate reservoir geologic models (three of which are multimillion-cell models) from Africa, North America, and South America were employed as benchmarks and working data sets to develop and validate the new technique. The technique has the advantage of handling the more irregular geometries [i.e., pinchouts, faults, and flexible simulation grids such as the Perpendicular Bisection (PEBI) grid].
Mechanistic Modeling of Two-Phase Flow in Deviated Wells
Authors: Kaya A. S. , Sarica C. , Brill J. P. 
Published: December 2007

Summary
A mechanistic model was developed to predict flow pattern and flow characteristics such as pressure drop and liquid holdup in vertical and deviated wells. The model includes five flow patterns: bubbly, dispersed-bubble, slug, churn, and annular flows.
Flow-pattern prediction incorporates the transition models proposed by Barnea1 (or Taitel et al.2) for dispersed-bubble flow, Ansari et al.3 for annular flow, Tengesdal et al.4 for churn flow, and a new bubbly-flow transition model. For each predicted flow pattern, a separate hydrodynamic mechanistic model is proposed. A new hydrodynamic model for bubbly flow has been developed, and the Chokshi5 slug-flow model has been modified significantly. The Tengesdal et al. and Ansari et al. models have been adopted for churn and annular flows, respectively.
The model is evaluated with a well databank of 2,052 cases covering a broad range of field data. Pressure drop predictions with the model are also compared with those using the Ansari et al., Chokshi, Hasan and Kabir,6 and Tengesdal7 mechanistic models, and the Aziz et al.8 and Hagedorn and Brown9 correlations. The results of the comparison study show that the proposed mechanistic model performs the best and agrees with the data.
Design and Installation of a Sand-Separation and -Handling System for a Gulf of Mexico Oil Production Facility
Authors: Rawlins C. H. , Wang I. I. 
Published: December 2007

Summary
A comprehensive system for the separation and handling of sand from produced fluids was designed and installed on a facility in the Gulf of Mexico. This system involves two multicone desander systems, one on the water outlet and one on the oil outlet of a low-pressure separator, to provide separation of sand from produced fluids. The separated solids are collected, dewatered, and transported to a unique, simple-solids handling system designed for complete fluid containment and safe handling. The focus of this paper is to present the design of the separation and handling system and to discuss the various challenges encountered during and after commissioning. The topics covered include desander operation (pressure drop and separation), slurry discharge from the desander, dewatering of slurry, recycling of fluids, and transport of the collected solids from platform to shore.
Material Balance Above the Bubble Point
Authors: Hobson G.D. , Mrosovsky I. 
Published: December 2007

Material balance relationships for expansion-type reservoirs above the bubble point have been discussed in recent years by H. N. Hall and M. F. Hawkins, Jr. The former drew attention to the effects of rock compressibility, and the latter to the effects of the compressibility of any interstitial water. Hawkins derived a general relationship which took note of oil, water and rock compressibilities, and then by assuming first, the absence of interstitial water and secondly, no effects due to interstitial water or rock compressibility, obtained relationships symbolically of the same form as those previously derived directly by Hall.
Hawkins defined his terms clearly, and noted an approximation, due to the omission of a term involving the product of two compressibilities, made in reaching his final equation. There is, however, possible ambiguity with regard to Hall's written definition of the oil production term. One interpretation would mean that the produced oil and initial oil-in-place, if both required as stock tank barrels, would be obtained by using different formation volume factors in the conversion in order to satisfy the conditions implicit in Hall's formulae. The other would involve an approximation which, if used, was not stated. In both Hall's and Hawkins' studies the effect of the approximation or inconsistency is very slight. Nevertheless, it may be justifiable to give a somewhat more consistent derivation, since the complexity of the final relationships is not thereby greatly increased.
The Responsibility of Geologists and Petroleum Engineers in Meeting Exploration Demands in the Future
Authors: Halbouty Michel T. 
Published: December 2007

Abstract
The oil industry should be preparing right now for the high future demands of petroleum products, even though there are adequate reserves to handle present demand. Engineers and geologists, in particular, should cooperate and strive to use data at hand to increase tile efficiency of methods of finding new oil. Several important areas of cooperation are discussed and examples are given of instances in which such cooperation led to significant discoveries. Broader responsibilities of engineers and geologists are also pointed out.
Introduction
In 1962, the United States produced 3.02 billion bbl of crude oil and natural gas liquids. This is the first time that total liquid hydrocarbon production has exceeded 3 billion bbl. In 1962, the United States also set a new record for natural gas by producing 13.7 trillion cu ft. At this rate of production, this country will have consumed its proven reserves of 38.7 billion bbl of liquid hydrocarbons in 12 1/2 years and its proven reserves of 273.8 trillion cu ft of gas in 20 years. Annual demand, however, is increasing at an established rate of 2 1/2 to 3 1/2 per cent/year for oil and 4 1/2 to 5 per cent/year for gas. Therefore, in order to maintain an adequate reserve position during the next 10 years, the United States must find 45 billion bbl of oil and 275 trillion cu ft of gas. In short, the petroleum industry's geologists and engineers must find and produce more oil and gas in the foreseeable future than has ever been produced in an equivalent previous period. In view of this challenge, one can only conclude that the basic law of supply and demand on which this country's economy is, or has been, based promises a bright future for the industry.
This rosy glow in the early morning sky is viewed at the moment, however, by an industry which is in a deep valley full of dark shadows. At a time when all signs point to an ever increasing demand for new reserves and greater productive capacity, the industry finds itself with more products to sell than present consumers can use. In addition, there is the problem of the loss of investment capital as a result of the continuing threat of increasing federal control. The sum of these two factors equals a reduction in exploration and production which is revealed by declining activity over the last 10 years.
Industry Reaction
Fig. 1 presents a brief resume of exploration and development in the United States since 1953. Geophysical activity is down 50 per cent from a high of 8,240 crew months in 1955 to a low of 4,231 crew months in 1962. Exploratory drilling is down 33 per cent from a peak of 16,207 wells in 1956 to 10,797 wells in 1962. Finally, as the inevitable result of a decline in exploration, development drilling has dropped 16 per cent from a high of 42,000 wells in 1956 to 35,408 in 1962.
JPT
P. 239ˆ
Oil Recovery by Gravity Drainage
Authors: Hagoort J. 
Published: December 2007

Abstract
Recent observations have indicated surprisingly high oil recoveries for gravity drainage. This has prompted us to reexamine gravity drainage as an oil recovery process. It is shown that oil relative permeability is a key factor. For accurate measurement of this oil relative permeability, we have developed a new method based on centrifugal gas/oil displacement in small cores. Several oil relative permeabilities for various rock types are presented. These relative permeabilities confirm that gravity drainage in water-wet, connate-water-bearing reservoirs can be very effective for oil-recovery.
Effect of Stratification on Relative Permeability
Authors: Corey A.T. , Rathjens C.H. 
Published: December 2007

Introduction
Although the oil industry has been aware of the directional variability of permeability in porous rock, the directional variability of relative permeability has been largely ignored. Yet it is apparent that such an effect must be present in a system in which the distribution of oil and gas within the porous matrix is controlled by capillary forces.
It is easy to visualize a rock composed of layers of fine and coarse material such that gas flow across the bedding planes would take place only after the average oil saturation had been reduced to a very low value. The fine layers, because of their greater capillarity, would remain saturated and act as barriers to the flow of gas after the coarse layers had been desaturated. Flow of gas parallel to the bedding planes would obviously take place at a much greater liquid saturation.
Without more complete information concerning the geology of a reservoir than is generally available, it is not possible to predict exactly how such phenomena would affect the over-all performance of an oil field. It is possible, however, to predict qualitatively the effect of stratification on relative permeability measurements made on laboratory cores.
In this investigation the effect of stratification was studied analytically by assuming that two porous materials with different capillary pressure-desaturation curves (but identical relative permeability curves) were in contact and in capillary equilibrium. As a qualitative check on the analytical results, cores having various degrees of visible stratification were used for relative permeability measurements made with fluids flowing both parallel and perpendicular to the bedding planes. A quantitative check was considered impractical because of the difficulty of devising models in which two materials of predetermined properties could be joined without the plane of contact becoming a discontinuity.
Theoretical Considerations and Assumptions
The assumption of capillary equilibrium in an oil-gas system implies that the difference in pressure between oil and gas is everywhere the same.
A Coupled Model for Three-Phase Capillary Pressure and Relative Permeability
Authors: Hustad Odd Steve 
Published: December 2007

SummaryA fully coupled formulation for three-phase capillary pressure and relative permeability is presented. The formulation incorporates hysteresis and miscibility on both capillary pressure and relative permeability, simultaneously. Consistency is ensured for all three two-phase boundary conditions through the use of two-phase data and the application of normalized saturations.Simulation examples of water-alternating-gas (WAG) injection are demonstrated using water-, mixed-, and oil-wet capillary pressure and relative permeability curves, both exhibiting hysteresis. The examples represent typical core-flooding scales in the centimeter to meter range. Discussions and illustrations are given demonstrating the importance of the functional dependency and the extrapolation of two-phase capillary pressure values to three-phase flow properties.
Simulation and Performance Prediction of a Large-Scale Surfactant/Polymer Project
Authors: Lake Larry W. , Johnston James R. , Stegemeier George L. 
Published: December 2007

Abstract
This paper presents a performance prediction technique for the response of a large-scale chemical flood. The technique involves the sequential use of a detailed finite difference simulator and a streamtube program. Although approximate, the technique avoids the difficulties usually associated with the independent use of either simulator.