bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mechanisms Causing Disproportionate Permeability Reduction in Porous Media Treated With Chromium Acetate/HPAM Gels
Authors: Willhite G. Paul , Zhu H. , Natarajan D. , McCool C. S. , Green D. W. 
Published: December 2007

Summary
It is well established that treatment of porous rocks with gelled polymer systems can cause the permeability of water at residual oil saturation to be reduced by one to three orders of magnitude more than the permeability of oil at the water saturation that is immobile after treatment. This phenomenon is called disproportionate permeability reduction (DPR) and is of interest because application of gel treatments in production wells has potential to reduce water production.
The mechanisms that cause this phenomenon are not well understood. This paper describes how permeability to oil and water is developed in pore space that is filled with a chromium acetate/ partially hydrolyzed polyacrylamide (HPAM) gel and proposes a mechanism for DPR based on the interpretation of the experimental data. Experimental data for the flow of oil and brine were obtained in unconsolidated sandpacks and in Berea sandstone cores with and without residual oil saturation after a chromium acetate/Alcoflood 935 gelant was injected and gelled in situ.
Interpretation of the experimental data suggests that oil permeability develops as oil penetrates into the gel-filled pore space, dehydrating the gel by displacing brine from the gel structure and creating "new flow channels" within or around the gel. The "new pore space" is a fraction of the original porosity, and the permeability to oil is reduced substantially from its value before placement and in-situ gelation of the gelant. Subsequent brine injection displaces oil from these flow channels but traps some of the oil in the new pore space as a residual saturation. The trapping of residual oil in the new pore space causes the disproportionate reduction in brine permeability because the brine flows primarily in the pore channels created by dehydration of the gel even though the gel has some brine permeability. When gelant is placed in a matrix containing residual oil, dehydration of the gel reconnects some of the trapped oil, and the oil permeability increases. Subsequent brine displacement experiments conducted at the same pressure drop showed that initial brine permeability was reduced by factors of 100 to 1,000 more than the oil permeability, verifying the existence of DPR.
Linearly Supported Radial Flow—A Flow Regime in Layered Reservoirs
Authors: Guo Boyun , Stewart George , Toro Mario 
Published: December 2007

SummaryThis paper discusses pressure responses from a formation with two communicating layers in which a fully penetrated high-permeability layer is adjacent to a low-permeability layer. An analytical reservoir model is presented for well-test analysis of the layered systems, with the bottom of the low-permeability layer being a constant-pressure boundary. The strength of the support from the low-permeability layer is characterized with two parameters: layer bond constant and storage capacity.
Interpretation of Horizontal-Well Production Logs: Influence of Logging Tool
Authors: Ozkan E. , Sarica C. , Haci M. 
Published: December 2007

Summary
This paper investigates the disturbance of horizontal-wellbore flow conditions by a production-logging tool and its influence on well-bore flow-rate and pressure measurements. An analytical model is used in the investigation, and single-phase liquid flow is assumed. It is shown that the influence of the production-logging tool manifests itself in low-conductivity and high-rate wells; this effect may be ignored if the dimensionless well conductivity exceeds 500 and the Reynolds number is lower than 100,000. Results indicate that production logs in low-conductivity horizontal wells may not display low-permeability zones along the well.
Validation of Near-Wellbore Fracture-Network Models With MDT
Authors: Verga F.M. , Giglio G. , Masserano F. , Ruvo L. 
Published: December 2007

SummaryA new approach was attempted to validate the reconstructed internal geometry of a fractured reservoir by reproducing the reservoir dynamic behavior monitored during modular dynamic tests (MDTs). The description of the reservoir fracture network was achieved by integrating relevant data that could be collected from wireline logs, conventional cores, small drilling-mud-loss analysis, and field-scale observations from outcrop analog inspection. Fracture types, properties, and distributions were thus defined, and a static model of the fractured reservoir was generated stochastically. The dynamic behavior of the fractured system was reproduced by a finite-element flow model. Consistency was required between the observed and simulated pressure data to ensure that the reservoir geometry was modeled adequately. Analysis of the model response as a function of the assigned fracture parameters and comparison between the observed and simulated dynamic behavior allowed achievement of a satisfactory description of the reservoir effective fracture network.
Fast and Robust Algorithm for Compositional Modeling: Part I—Stability Analysis Testing
Authors: Firoozabadi Abbas , Pan Huanquan 
Published: December 2007

SummaryGiven pressure, temperature, and composition of a fluid, one desires to determine whether the single phase state is stable. This problem is, in principle, much simpler than phase-behavior calculations. For certain applications, such as compositional-reservoir modeling, stability testing can be the most important item for efficient phase-behavior calculations.In this paper, we use the tangent-plane-distance (TPD) in the reduced space to perform stability analysis testing. The results reveal that there are major advantages in the reduced space. One interesting feature of the transformation is that the TPD surface becomes smooth and has one minimum. The combination of a single minimum and the surface smoothness contributes to a remarkable robustness in calculations.
Hydraulic Characterization of Fractured Reservoirs: Simulation on Discrete Fracture Models
Authors: Sarda S. , Jeannin L. , Basquet R. , Bourbiaux B. 
Published: December 2007

SummaryAdvanced characterization methodology and software are now able to provide realistic pictures of fracture networks. However, these pictures must be validated against dynamic data like flow-meter, well-test, interference-test, or production data and calibrated in terms of hydraulic properties. This calibration and validation step is based on the simulation of those dynamic tests. What has to be overcome is the challenge of both accurately representing large and complex fracture networks and simulating matrix/fracture exchanges with a minimum number of gridblocks. This paper presents an efficient, patented solution to tackle this problem. First, a method derived from the well-known dual-porosity concept is presented. The approach consists of developing an optimized, explicit representation of the fractured medium and specific treatments of matrix/fracture exchanges and matrix/matrix flows. In this approach, matrix blocks of different volumes and shapes are associated with each fracture cell depending on the local geometry of the surrounding fractures. The matrix-block geometry is determined with a rapid image-processing algorithm. The great advantage of this approach is that it can simulate local matrix/fracture exchanges on large fractured media in a much faster and more appropriate way. Indeed, the simulation can be carried out with a much smaller number of cells compared to a fully explicit discretization of both matrix and fracture media. The proposed approach presents other advantages owing to its great flexibility. Indeed, it accurately handles the cases in which flows are not controlled by fractures alone; either the fracture network may be not hydraulically connected from one well to another, or the matrix may have a high permeability in some places. Finally, well-test cases demonstrate the reliability of the method and its range of application.
Deconvolution of Well-Test Data as a Nonlinear Total Least-Squares Problem
Authors: Schroeter T. von , Hollaender F. , Gringarten A. C. 
Published: December 2007

Summary
We present a new time-domain method for the deconvolution of well test data which is characterized by three novel features: (1) Instead of the rate-normalized pressure derivative itself, we estimate its logarithm, which makes explicit sign constraints unnecessary; (2) the formulation accounts for errors in both rate and pressure data, and thus amounts to a Total Least Squares (TLS) problem; and (3) regularization is based on a measure of the overall curvature of its graph. The resulting separable nonlinear TLS problem is solved using the Variable Projection algorithm. A comprehensive error analysis is given. The paper also includes tests with a simulated example and an application to a large field example.
The Application of Pulsed Neutron Decay Time Logs To Monitor Waterfloods With Changing Salinity
Authors: Youngblood W.E. 
Published: December 2007

A combination of a pulsed neutron decay time log (TDT) TM) and an induction log has been successful in monitoring the early stages of a low- salinity waterflood. This technique has proved successful in determining the salinity of the mixture of flood-water and formation water so that water saturation can be determined behind the floodfront.

Introduction
During the early development of the giant Ghawar and Abqaiq fields of Saudi Arabia, Arabian American Oil Co. (Aramco) decided that the most efficient means of maintaining reservoir pressure would be through a peripheral water injection system. Accordingly, injection wells were located downdip from the original oil/water contact and as far away as 5 km from the nearest producing well.Initially, the sources of injection water were massive sandstone aquifers of the Wasia and Biyadh formations, which overlie the entire Ghawar and Abqaiq structure. Water salinities from these aquifers vary from 5,000 to 18,000 ppm. Water from the oil-producing zone of the Arab-D reservoir has salinities of about 200,000 ppm. In addition to the Wasia and Biyadh source, seawater with salinities of about 57,000 ppm now is being used in some areas.The producing interval, the Arab-D reservoir, typically is a calcarenitic-to-aphanitic limestone with some dolomitic stringers. Porosity is 20% on the average but can be as high as 30 to 32% in the upper part of the reservoir. Permeabilities range from a few part of the reservoir. Permeabilities range from a few millidarcies to over 1 darcy. Normally the producing wells are completed openhole with 7-in. casing set to the top of the reservoir. Usually the reservoir section is drilled out below the 7-in. casing approximately 200 to 250 ft below the casing shoe, several hundred feet above the present oil/water contact. Two-in. tubing, which will act as a kill string, normally is run just above the casing shoe, and the well is produced up the casing annulus.Most injection wells are completed openhole, the same way as producers. Injection rates tend to vary from area to area, ranging from 5,000 to more than 50,000 B/D.As early as 1960, a feasibility study made by Aramco successfully determined the rate of oil/water contact advance and calculated the oil displacement efficiency of waterflooding in the Arab-D reservoir. For this study, observation wells were drilled into the oil/water contact to observe fluid changes with time. The wells were completed openhole with a highly resistive fluid such as fuel oil in the wellbore. Initially the induction and sonic logs were run through the reservoir section. Subsequent induction logging was done at regularly scheduled periods to observe changes in oil saturation with time.The study assumed, at the time, that the advancing water at the oil/water contact would be entirely Arab-D formation water. Therefore, the values of water saturation could be calculated from induction and sonic logs using the classic Archie equation:
(1)
JPT
P. 957
Production Data Integration in Sand/Shale Reservoirs Using Sequential Self-Calibration and GeoMorphing: A Comparison
Authors: Wen X. -H. , Tran T. T. , Behrens R. A. , Gomez-Hernandez J. J. 
Published: December 2007

Summary
The stochastic inversion of spatial distribution of lithofacies from multiphase production data is a difficult problem. This is true even for the simplest case, addressed here, of a sand/shale distribution and under the assumption that reservoir properties are constant within each lithofacies. Two geostatistically based inverse techniques, sequential self-calibration (SSC) and GeoMorphing (GM), are extended for such purposes and then compared with synthetic reference fields. The extension of both techniques is based on the one-to-one relationship existing between lithofacies and Gaussian deviates in truncated Gaussian simulation. Both techniques attempt to modify the field of Gaussian deviates while maintaining the truncation threshold field through an optimization procedure. Maintaining a fixed threshold field, which has been computed previously on the basis of prior lithofacies proportion data, well data, and other static soft data, guarantees preservation of the initial geostatistical structure. Comparisons of the two techniques using 2D and 3D synthetic data show that the SSC is very efficient in producing sand/shale realizations matching production data and reproducing the large-scale patterns displayed in the reference fields, although it has difficulty in reproducing small-scale features. GM is a simpler algorithm than SSC, but it is computationally more intensive and has difficulty in matching complex production data. Better results could be obtained with a combination of the two techniques in which SSC is used to generate realizations identifying large-scale features; then, these realizations could be used as input to GM for a final update to match small-scale details.
Dynamic Optimization of Waterflooding With Smart Wells Using Optimal Control Theory
Authors: Brouwer D. R. , Jansen J.-D. 
Published: December 2007

Summary
We used optimal control theory as an optimization algorithm for the valve settings in smart wells. We focused on their use in injectors and producers for the waterflooding of heterogeneous reservoirs. As a followup to an earlier intuitive optimization approach, a systematic dynamic optimization approach based on optimal control theory was developed. The objective was to maximize recovery or net present value of the waterflooding process over a given time period. We investigated the scope for optimization under purely pressure- and purely rate-constrained operating conditions, and concluded that: (1) for wells operating on bottomhole-pressure constraints, the benefit of using smart wells is mainly reduced water production rather than increased oil production, and (2) for wells operating on rate constraints, there is generally a large scope for accelerating production and increasing recovery, in combination with a drastic reduction in water production.
Combining Global and Local Optimization Techniques for Automatic History Matching Production and Seismic Data
Authors: Mantica S. , Cominelli A. , Mantica G. 
Published: December 2007

SummaryGradient-based optimization techniques are increasingly adopted by oil industries for computer-aided history matching because of the great timesaving they can offer over conventional trial-anderror approaches. However, these methods lead to the identification of a single set of parameters, thus neglecting the inherent nonuniqueness of the solution of the underlying inverse problem. In this paper we propose a new approach that couples a chaotic sampling of parameter space with a local minimization technique. Through the evolution of a nonlinear dynamical system, we identify several points to be successively used as initial guesses for a local gradient-based optimizer. This provides a series of alternative matched models with different production forecasts that improve the understanding of the possible reservoir behaviors. The validity of this approach has been proven on a synthetic reservoir derived from a real west Africa field.
Mobility of Foam in Heterogeneous Media: Flow Parallel and Perpendicular to Stratification
Authors: Tanzil Dicksen , Hirasaki George J. , Miller Clarence A. 
Published: December 2007

SummaryExperiments in homogeneous and heterogeneous sand-packed columns showed that the foam mobility in the two cases could differ by two orders of magnitude. The difference is because of the generation of foam lamellae by snap-off for flow across an abrupt increase in permeability. This mechanism is shown to be dependent on the degree of permeability contrast and the gas fractional flow. It has important implications for the degree of gravity segregation of gas and liquid in field-scale recovery processes.
Electrofacies Characterization and Permeability Predictions in Complex Reservoirs
Authors: Lee Sang Heon , Kharghoria Arun , Datta-Gupta Akhil 
Published: December 2007

Summary
We propose a two-step approach to permeability prediction from well logs that uses nonparametric regression in conjunction with multivariate statistical analysis. First, we classify the well-log data into electrofacies types. This classification does not require any artificial subdivision of the data population; it follows naturally based on the unique characteristics of well-log measurements reflecting minerals and lithofacies within the logged interval. A combination of principal components analysis (PCA), model-based cluster analysis (MCA), and discriminant analysis is used to characterize and identify electrofacies types. Second, we apply nonparametric regression techniques to predict permeability using well logs within each electrofacies. Three nonparametric approaches are examined—alternating conditional expectations (ACE), generalized additive model (GAM), and neural networks (NNET)—and the relative advantages and disadvantages are explored.
We have applied the proposed technique to the Salt Creek Field Unit (SCFU), a highly heterogeneous carbonate reservoir in the Permian Basin, west Texas. The results are compared with three other approaches to permeability predictions that use data partitioning based on reservoir layering, lithofacies information, and hydraulic flow units (HFUs). An examination of the error rates associated with discriminant analysis for uncored wells indicates that data classification based on electrofacies characterization is more robust compared to other approaches. For permeability predictions, the ACE model appears to outperform the other nonparametric approaches.
Productivity of Selectively Perforated Vertical Wells
Authors: Yildiz Turhan 
Published: December 2007

Summary
This study presents analytical models to predict the productivity of selectively perforated vertical wells. The models consider arbitrary phasing angle, nonuniform perforation size and length, and formation damage around perforations. The accuracy of the models was verified against the results from the experimental studies, the semi-analytical correlation, and the numerical models all available in the literature. Unique applications of the models are presented. A comprehensive sensitivity study showing the impact of different perforation schemes on well productivity is documented.
Thermal Stability of Surfactants for Reservoir Application
Authors: Handy L. L. , Amaefule J. O. , Ziegler V. M. , Ershaghi I. 
Published: December 2007

AbstractThe thermal stabilities of several sulfonate surfactants and one nonionic surfactant have been evaluated. The decomposition reactions have been observed to follow first-order kinetics. Consequently, a quantitative measure of a surfactant's stability at a given temperature is its half-life. Furthermore, the activation energy can be estimated from rate data obtained at two or more temperatures. This permits limited extrapolation of the observed decomposition rates to lower temperatures for which the rates are too low for convenient measurement. The surfactants we investigated are being considered for steamflood additives and need to be relatively stable at steam temperatures.None of the surfactants evaluated to date has the requisite stability for use in steamfloods. The most stable petroleum sulfonate we have investigated has a half-life of 11 days at 180°C (356°F). With this half-life, substantial overdosing would be required to maintain the minimum effective surfactant concentration for the life of the flood. On the other hand, the estimated half-life for this surfactant at 93°C (200°F), calculated by extrapolation, would be 33 years.Tests with the nonionic surfactant, nonylphenoxy-polyethanol, have shown this material to have a very short half-life at steam temperatures, but it does appear to be more stable at concentrations greater than the critical micelle concentration (CMC). In limited tests, the sulfonates showed increased stability in the presence of a 2-M salt solution.
Impact of Rock Plasticity on Hydraulic Fracture Propagation and Closure
Authors: van Dam D. B. , Papanastasiou P. , de Pater C. J. 
Published: December 2007

SummaryWe performed scaled laboratory experiments of hydraulic fracture propagation and closure in soft artificial rock and outcrop rock samples. We also performed numerical simulations of the fracture behavior in plastic rocks with independently measured rock properties. The simulations aided in interpreting the measurements and extrapolating the results to field scale.Compared with elastic rock, plasticity induces a larger width for a given net pressure. However, the pressure to propagate fractures is only marginally increased and, in the case of the laboratory tests, was actually lower than expected from elastic behavior. The most dramatic effect of plasticity is that closure is much lower than the confining stress because of strong stress redistribution along the fracture.