bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Effect of Geological and Geomechanical Parameters on Reservoir Stress Path and Its Importance in Studying Permeability Anisotropy
Authors: Khan M. , Teufel L. W. 
Published: December 2007

Summary
Reservoir stress path is defined as the ratio of change in effective horizontal stress to the change in effective vertical stress from initial reservoir conditions during pore-pressure drawdown. Measured stress paths of carbonate and sandstone reservoirs are always less than the total stress boundary condition (isotropic loading) and are either greater or less than the stress path predicted by the uniaxial strain boundary condition. Clearly, these two boundary-condition models that are commonly used by the petroleum industry to calculate changes in effective stresses in a reservoir and to measure reservoir properties in the laboratory are inaccurate and can be misleading if applied to reservoir management problems. A geomechanical model that incorporates geologic and geomechanical parameters was developed to more accurately predict the reservoir stress path. Numerical results show that reservoir stress path is dependent on the size and geometry of the reservoir and on elastic properties of the reservoir rock and bounding formations. In general, stress paths become lower as the aspect ratio of reservoir length to thickness increases. Lenticular sandstone reservoirs have a higher stress path than blanket sandstone reservoirs that are continuous across a basin. This effect is enhanced when the bounding formations have a lower elastic modulus than the reservoir and when the reservoir is transversely isotropic. In addition, laboratory experiments simulating reservoir depletion for different stress path conditions demonstrate that stress-induced permeability anisotropy evolves during pore-pressure drawdown. The maximum permeability direction is parallel to the maximum principal stress and the magnitude of permeability anisotropy increases at lower stress paths.
NMR Relaxation of Clay/Brine Mixtures
Authors: Matteson A. , Tomanic J. P. , Herron M. M. , Allen D. F. , Kenyon W. E. 
Published: December 2007

Summary
Effective interpretation of nuclear magnetic resonance (NMR) logs in shaly sands requires an understanding of the NMR contribution of clays. Of particular importance is the role of clays in the rapidly relaxing part of the NMR signal.
In this study we measured the transverse relaxation time spectrum (T2) of brine mixed with four clays (illite, smectite, kaolinite and glauconite) as a function of compaction. The Larmor frequency was 2 MHz and the echo spacing 0.16 ms. Mild compaction was achieved by centrifuging the clay slurry at three successive pressures ranging from 1 to 125 psi. Highly compacted samples were produced in a uniaxial press at six sequential pressures ranging from 500 to 16,000 psi.
Each clay/brine slurry and its associated compacted sample showed a single peak in the T2 distribution spectrum. A second peak, which could be interpreted as the "clay-bound water," was never observed. The T2 peak position shifted to faster relaxation times as compaction increased, in proportion to the pore volume-to-surface ratio, Vp /As. The single peak and Vp /As proportionality are consistent with fast diffusion between the pore water and the monolayer of water on the clay surface. Surface relaxivity varied among the four clay minerals; glauconite, the clay with the highest magnetic susceptibility and iron content had the largest surface relaxivity.
These results have important implications for the interpretation of NMR logs in shaly sands. Because of the effects of compaction and to a lesser extent the iron content on a clay's T2 peak position, it is not possible to independently determine clay type from some characteristic relaxation time. These data also imply that it is not feasible to estimate the cation exchange capacity from a single time cutoff of the T2 distribution without additional information such as laboratory measurements or other log data.
Frontal Drive Production Mechanisms - A New Method for Calculating the Displacing Fluid Saturation at Breakthrough
Authors: Stutzman L.F. , Thodos George 
Published: December 2007

Abstract
A new graphical method, which is a modification of that proposed by Buckley and Leverett, is presented for the determination of the displacing fluid saturation at breakthrough for frontal drive mechanisms. This method is applicable to all types of fluids, which may be either soluble or insoluble in the oil at reservoir and injection conditions. This adaptation has unique advantages in handling problems in which either liquids or gases are the displacing fluids.

Introduction
In the displacement of oil from a reservoir with water or gas injected into the formation or by the expansion of a gas cap, the determination of breakthrough or flood advance is important to define the initial and subordinate phases of the operation. Thus, the determination of the displacing fluid saturation at breakthrough is fundamental to the establishment of over-all reservoir production. Methods for analyzing this saturation and for calculating production rates have been previously reported. All of these methods utilize the rate equation for linear flow developed by Buckley and Leverett.
A Computationally Efficient, Transient-Pressure Solution for Inclined Wells
Authors: Ozkan E. , Raghavan R. 
Published: December 2007

Summary
This work provides an efficient algorithm to compute transient pressure responses of inclined wells. The solution is derived in the Laplace domain and cast into computationally efficient forms for all inclination angles. The algorithm allows the computation of pressures and derivatives at the wellbore as well as at observation points. Short- and long-time approximations for the evaluation of pressure responses are also provided. The long-time approximation is used to derive a general pseudoskin expression that is applicable for all inclination angles. Example computations are presented in the forms of tables and figures to display the efficacy, accuracy, and the practical use of the algorithm.
A Semi-Analytic (p/z) Rate-Time Relation for the Analysis and Prediction of Gas Well Performance
Authors: Ansah J. , Knowles R. S. , Blasingame T. A. 
Published: December 2007

Summary
In this paper we present a rigorous theoretical development of solutions for boundary-dominated gas flow during reservoir depletion. These solutions were derived by directly coupling the stabilized flow equation with the gas material balance equation. Due to the highly nonlinear nature of the gas flow equation, pseudopressure and pseudotime functions have been used over the years for the analysis of production rate and cumulative production data. While the pseudopressure and pseudotime functions do provide a rigorous linearization of the gas flow equation, these transformations do not provide direct solutions. In addition, the pseudotime function requires the average reservoir pressure history, which in most cases is simply not available.
Our approach uses functional models to represent the viscosity-compressibility product as a function of the reservoir pressure/z-factor (p/z) profile. These models provide approximate, but direct, solutions for modeling gas flow during the boundary-dominated flow period. For convenience, the solutions are presented in terms of dimensionless variables and expressed as type curve plots. Other products of this work are explicit relations for p/z and Gp(t). These solutions can be easily adapted for field applications such as the prediction of rate or cumulative production.
We also provide verification of our new flow rate and pressure solutions using the results of numerical simulation and we demonstrate the application of these solutions using a field example.
Geostatistical Quantification of Geological Information for a Fluvial-Type North Sea Reservoir
Authors: Caers J. K. , Srinivasan S. , Journel A. G. 
Published: December 2007

SummaryAccurate prediction of petroleum reservoir performance requires reliable models of the often complex reservoir heterogeneity. Geostatistical simulation techniques generate multiple realizations of the reservoir model, all equally likely to be drawn. Traditional to geostatistics, geological continuity is represented through the variogram. The variogram is limited in describing complex geological structures as it measures correlation between rock properties at two locations only: it is a two-point statistic. Reservoir analogs such as outcrops can serve as training images depicting the interpreted geological structure. Due to scarcity of well data, the variogram models are often borrowed from such training sets. However, the same training images could be utilized to extract more complex information in the form of multiple-point statistics measuring the joint dependency between multiple locations.This paper compares a traditional variogram-based geostatistical model vs. a novel geostatistical method utilizing multiple-point statistics borrowed from training images. The comparison is made on the basis of flow performance for a typical North Sea reservoir. To obtain such comparison a "true" reference reservoir is generated using object-based simulation that depicts the complex intertwining of fluvial channels. Next, a different but similar reservoir is generated, termed the "training reservoir." The latter is used to extract the necessary structural information, be it variograms or multiple-point statistics, to build multiple geostatistical models of the true reservoir conditioned to sparse well data. A waterflood flow scenario with an inverted five-spot pattern is simulated using eclipse on the true reference and the various geostatistical models. Water breakthrough characteristics and water saturation distributions are used for comparison.
Optimizing Field Compressor-Station Designs
Authors: Pennybaker K. A. 
Published: December 2007

Summary
The main reasons for optimizing new field compressor-station designs and for upgrading existing stations are safety considerations, environmental impacts, and economics. With a well-designed compressor station it is possible to improve safety and environmental conditions while saving capital and increasing income.
A well-designed compressor station will be able to reduce the venting of heavy hydrocarbons from storage tanks, which can increase safety by reducing the possibility of forming explosive vapor clouds near venting tanks. An optimized design can improve safety by reducing the amount of hydrocarbon inventory located at the site. This can also save money by eliminating the need for a site to be covered by OSHA's process safety management.
Improving the environmental conditions by reducing the venting of hydrocarbons from the station's storage tanks is another advantage of a well-designed compressor station. The exhaust pollution can also be reduced by utilizing less compressor horsepower and reducing the trucking needs for station supplies and products such as methanol and condensate.
The economic advantages of an optimized compressor station include reduced operating costs and maximized product recovery. Reduction in operating costs are achieved through fuel savings from reduced horsepower requirements and reducing trucking costs. Maintenance activities are also typically less due to less horsepower, freeze ups, etc. Reducing the venting requirements means more gas is recovered as product, resulting in more income.
Evaluating and selecting the best configuration for a compressor-station design is an important decision. Many schemes have been evaluated for different situations and compared so that the most cost-effective configuration can easily be selected for new or existing station designs.
More Oil Using Downhole Water-Sink Technology: A Feasibility Study
Authors: Shirman E. I. , Wojtanowicz A. K. 
Published: December 2007

Summary
In this paper we report on recent R&D progress in downhole water sink (DWS) technology resulting in the establishment of a joint industry/Louisiana State U. (LSU) project-DWS Initiative. Presented are recent case histories of DWS design and successful field trials. The results are then analyzed comparatively in view of the superiority of DWS over single conventional completions. The analysis shows that, although DWS increases production of oil, its potential for reducing production of water is unknown and remains a controversial issue among operators.
The case history analysis is followed by results from the authors' theoretical and experimental study on water-cut (WC) suppression with DWS. The study was performed by comparing WC development in single (conventional) and dual (DWS) well completions for a broad range of oil reservoirs with bottom water columns. These theoretical results are supported with experiments conducted using a laboratory physical model of a dual/single completed well-reservoir system. The results included in this paper demonstrate the persistence and irreversible nature of water cut in conventional wells compared to its flexibility and easy control in DWS completions. Defined is the range of production rates where DWS may give a sizable, up to 40%, reduction of WC. It is also shown, with calculations, how to determine the expected WC reduction for a given reservoir and well-completion design.
Stabilizing Wellbores in Unconsolidated Formations for Fracture Stimulation
Authors: Nguyen P. D. , Brumley J. L. , Dewprashad B. T. , Dusterhoft R. G. , Weaver J. D. 
Published: December 2007

Summary
A wellbore stabilization system incorporating fracture stimulation has been developed and modeled in the laboratory for unconsolidated and dilatant formations. The profile of resin leakoff and penetration depth into the formation is relatively dependent on the pattern of perforations. Use of soluble particulates as a fluid-loss control agent proved to be effective in diverting resin, resulting in a uniform distribution of resin over the highly varying permeability interval. A significant drop in permeability of the near-wellbore area occurred after the resin treatment, but high productivity was re-established by connecting the wellbore with the untreated formation through highly conductive fractures. During companion testing of the resin-consolidation technique, the unconsolidated sandpack became a competent formation with compressive strength in excess of 2,000 psi. This competent material will be affected less by high drawdown pressures and stress cycling during production/shut-in cycles. The injection pressure required to fracture the consolidated wellbore showed an increase when compared to that of the untreated wellbore. Stress levels existing in the formation were shown to control the number and direction of generated fractures by passing the consolidated zone.
From Matrix Acidizing to Acid Fracturing: A Laboratory Evaluation of Acid/Rock Interactions
Authors: Bazin B. 
Published: December 2007

SummaryAcid fracturing and matrix acidizing are used as well-stimulation processes for carbonated reservoirs. In matrix acidizing, a deep penetration of wormholes around the well is required; in the acid-fracturing process, fluid leak-off must be limited and wormholes are prohibited. Laboratory tests are necessary to improve the design of these operations.Specific laboratory equipment was designed to reproduce downhole flow conditions. Matrix acidizing is a constant flow rate process, whereas acid in fracture is forced from the fracture wall to the formation, a process occurring at a constant pressure drop. This process was represented in the laboratory and a new tangential cell, aiming at working with straight acids in reservoir temperature and pressure conditions, was specially designed to handle this application. The first part of the paper presents a methodology for the evaluation of acid/rock properties. Results of acid injections at constant flow rates are compared to results obtained from injections at constant pressure drop. Experiments have been conducted with limestone core samples of different petrophysical properties. Performance of different acid formulations including straight acids, emulsions, and gels was evaluated.Results are discussed in terms of acid propagation rates and dissolution patterns. They are analyzed using x-ray computed tomography. They are classified into wormholes, i.e., branched patterns of large extension, and compact ones. Finally, recommendations are made concerning operating conditions favorable for matrix acidizing. On the opposite, conditions are given to limit dissolution and to restrict fluid loss for the acid fracturing application.
Some Data Processing and Engineering Calculations With Slow to Medium Speed Computers
Authors: Walker John W. 
Published: December 2007

Abstract
The paper describes methods of solving several reservoir engineering and data processing problems using slow to medium speed computing machines. The problems handled are:Solution of the Hurst-van Everdingen material balance equation for which at first only water influx terms and y curves for PVT samples were calculated with the IBM 602A and 604 computers, while later the complete solution of the equation was programmed on the IBM 607 computer. The application of this equation requires computing cumulative water influx volumes at successive dates and matching these figures with the difference between the corresponding cumulative reservoir volumes withdrawn, and the corresponding cumulative expansions of the initial volume of reservoir oil and gas.Vapor-liquid equilibrium flash calculations which are solved rapidly with the IBM 602A or 604. Auxiliary calculations were made to convert the results into usable engineering quantities.Statistical analyses, performed on core data for several fields, providing a better understanding of the reservoir characteristics.Preparation of the annual (statistical) reserve report. This report starts with the previous year's figures for the gross and net reserves, cumulative and ultimate production, separated into oil, condensate and total liquid figures by leases. Revisions to reserves, classified according to 10 categories such as discoveries, new zones, extensions, etc. are added to the opening reserves and ultimate production figures, while the yearly production figures are subtracted from the revised figures and added to the cumulative figure. Statistical data concerning leasehold titles and ownership fractions, well counts, etc. are recorded. All figures are summarized according to zones, fields, leases, divisions and areas.Miscellaneous uses of analytical procedures for production accounting figures, such as oil pipe line runs, etc. provided better control of production operations.

Introduction
The annual reserve report is a statistical statement of gross and net reserves, including revisions of reserve estimates and production during the year. The responsibility for preparing this report was assigned to reservoir engineers and by 1952 the report required considerable engineering, clerical and stenographic time.
Accuracy Prediction for Directional Measurement While Drilling
Authors: Williamson H. S. 
Published: December 2007

Summary
In this paper a new method for predicting wellbore position uncertainty which responds to the current needs of the industry is described. An error model applicable to a basic directional measurement while drilling (MWD) service is presented and used for illustration. As far as possible within the limitations of space, the paper is a self-contained reference work, including all the necessary information to develop and test a software implementation of the method. The paper is the product of a collaboration between the many companies and individuals cited in the text.
Enhanced Interpretation of Temperature Surveys Taken During Injection or Production
Authors: Murphy Hugh D. 
Published: December 2007

Summary
Temperature surveys run during well injection or production can reveal not only intake or production intervals but also the rate of flow. From previous work, the flowrate analysis is based on the "subtangent" or "delta function," which is simply the change in temperature induced by the flow divided by the thermal gradient. This paper investigates accuracy and limitations. of this simplified analysis, and provides design guides for selecting conditions that optimize interpretation. Methods for distinguishing flow-rate changes from changes in formation properties or well radius also are presented.

Introduction
Diagnostic temperature surveys in wells are at least 60 years old. The earliest use of temperature measurements was primarily for geophysical and geological purposes. For example, determining geothermal gradients, required for regional heat flow studies, was reported by van Orstrand1 and Heald.2 Lithological variations were identified by local departures from the prevailing geothermal profile that were caused by thermal property variations of the formations.3 In the mid-1930's attention turned toward using temperature surveys to diagnose well completion and production problems.4 Deussen and Guyod5 described it technique for determining the position of cement emplacement that relied on the temperature increase caused by heat of hydration. Lost circulation zones were identified as warm or cool temperature anomalies, depending on whether the drilling fluid was hotter or colder than the thieving formation.6 Potential gas production zones were inferred from local anomalies caused by the cooling effect of the depressurized gas as it entered the well.6
More recently attention has focused on the use of temperature surveys to infer flow rate profiles within wells. The methods can be applied to either injection or production wells. For example, in cased wells positions and magnitudes of casing leaks can be identified. In openhole sections the fluid intake or production strata can be located, and the injectivity or productivity of formations can be profiled. In this manner temperature surveys are similar to flowmeter. surveys (e.g., a spinner survey) except that unlike flowmeter surveys temperature surveys can detect flows behind casing7 - e.g., water aquifer flows - and are particularly useful for locating hydraulic fractures.8
Improving the Working Environment and Drilling Economics Through Better Understanding of Oil-Based Drilling Fluid Chemistry
Authors: James R. W. , Schei T. , Navestad P. , Geddes T. A. , Nelson M. G. , Webster D. 
Published: December 2007

Summary
The relationships between oil-based drilling fluid composition and the associated vapors have been quantified. The study documents the long- and short-term changes in base oil selection and fluid compositions. The study is based on the generation and assessment of data collected from the vapor emissions of oil-based drilling fluids with varying compositions and at a range of temperatures.
The purpose of the study was to enable a better understanding of the potential working environment hazards when using mineral oil-based drilling fluids. One result of this understanding is that new rig construction designs and older rig upgrades can be performed more informatively. This will reduce the repetition of continual modification costs.
Pore-Network Model of Flow in Gas/Condensate Reservoirs
Authors: Wang Xiuli , Mohanty K. K. 
Published: December 2007

SummaryA pore-scale network model is presented here for gas-condensate flow. Porous media are modeled by networks of pore bodies interconnected by pore throats. Pore-level laws are identified from previously published micromodel and multiphase pipe flow experiments. The condensate can flow due to three mechanisms: pressure gradient within the sample-spanning condensate phase, movement of condensate slugs, and condensate droplets carried by the gas flow. Inertial effects are important for high rate gas flows. The relative permeabilities and non-Darcy coefficients have been computed for the low capillary number and low condensate saturation-high pressure gradient flow regimes.