bluuebunny/crossref_metadata_2025_split huggingface dataset:
Laminated Reservoir Evaluation in a Case of High Apparent Dip
Authors: Frisch G. J. , Gulick B. D. , Manning M. J. 
Published: December 2007

Abstract
In several offshore reservoirs composed of thin, interbedded sands and shales, a recently reported technique to correct standard induction logs for the effects of formation dip is incorporated into an established method for the well log analysis of laminated reservoirs to yield a superior petrophysical characterization.
Both shale anisotropy and bedding effects are included in the correction of the induction log for apparent dip. In a single well, electrically anisotropic properties of shales are difficult to determine solely by well logs. In the example reservoir, multiple wells with varying hole deviation were drilled from the same platform. By analyzing logged intervals from different wells, the electrical anisotropy of the shales is determined and appropriate corrections are made to the induction log.
Procedurally, a laminated reservoir analysis technique using a dipmeter or another high resolution shale indicator is first applied to the log data. Induction resistivities are corrected for dip effects arising from both sand/shale boundaries and shale anisotropy using an estimate of anisotropy. Then, corrected induction resistivities are used in the laminated reservoir analysis technique. Finally, parameters related to shale anisotropy are varied so that the analyses of wells with high and low apparent dip are consistent.
Quantitative analysis within each individual well is improved using these methods; more importantly, the combined techniques allow comparative evaluations between wells with significantly different hole deviations. Therefore, inclusion of dip effect corrections yields a more accurate well-to-well comparison in laminated reservoirs.
Fracture Evaluation from Quantitative Azimuthal Resistivities
Authors: Faivre Ollivier 
Published: December 2007

Abstract
The ARI* Azimuthal Resistivity Imager is a standard laterolog equipped with an additional segmented electrode. This segmented electrode provides twelve deep calibrated azimuthal resistivity measurements. As any electrical device, the ARI tool is sensitive to fractures filled with conductive fluid. Finite-element modeling was performed to study the tool response to fractures. It shows that techniques similar to those used to characterize fractures with the FMI* Fullbore Formation Microlmagcr can be used with the ARI tool. But it also demonstrates that the extension of the fracture (or the length of mud invasion for an oil filled fracture) and its width (aperture) are equally important parameters when characterizing the fracture. From the resistivity image, the geometry of the fracture (dip and azimuth) can be computed. A lower limit of the fracture aperture and a lower limit of the fracture extension can be estimated from the azimuthal resistivities. Log examples illustrate the proposed technique.
Field Application of a New Well Testing Concept for Evaluating Damaged and Stimulated Horizontal Wells
Authors: Malekzadeh D. , Azari M. , Day J. J. , Abass H. 
Published: December 2007

Abstract
The potential for severe formation damage around horizontal wells exists due to the increased time of formation exposure to the drilling fluids as compared to the time that a vertical well is exposed to these fluids. This paper explains that the combined effect of the formation damage and the presence of impermeable barriers and low permeability regions in the vicinity of some sections of the horizontal wellbore will manifest itself as skin factor in well test analysis if the total drilled length of the horizontal section is used in the calculations. The purpose of this paper is to present practical new equations, based on a recently introduced concept in well performance analysis, for evaluating the actual length of the horizontal well contributing to production. It is determined that the performance of a horizontal well with mechanical skin and of length Xf1 can be substituted by the performance of a horizontal well of length Xf2 with no skin. Xf2 is smaller than for a damaged well and is greater than for a stimulated well. By combining the concepts of equivalent horizontal well length and equivalent wellbore radius, one will be able to evaluate the performance of a horizontal well in comparison to its expected performance and to subsequently relate it to an equivalent stimulated vertical well. The new equations and guidelines can be used to determine the magnitude of formation damage around horizontal wells and to evaluate the success of a stimulation treatment
The concept of effective horizontal well length developed in this paper was applied to the pressure drawdown analysis of well test data obtained on a horizontal well. A good match was obtained which were used to calculate the parameters of interest.
Furthermore, in the analysis of interference tests with mechanical skin damage at the active horizontal well, the observation well will seem as if it is closer to the active horizontal well than it actually is. The effective horizontal well length is obtained from type curve matching which will then yield the mechanical skin factor.
It is expected that the concept of effective horizontal well length and effective hydraulic fracture length will gradually be adopted and implemented by the petroleum engineers and by groundwater hydrologists in the evironmental engineering discipline.
Coupling Pressure and Rate-Time Data in Performance Analysis of Horizontal Wells: Field Examples
Authors: Vo D. T. , Madden M. V. 
Published: December 2007

ABSTRACT
Horizontal well performance analysis can be difficult. Pressure transient interpretation on horizontal wells is complicated by the possibility of a multiple-flow-regime appearing during testing, and even by the non-appearance of a particular flow regime due to wellbore storage and testing time limitations. As a result, interpretation of horizontal well pressure transient data alone may be ambiguous and unreliable for performance predictions. Rate-time data is frequently available and can be used to improve the analysis, but is often overlooked in horizontal well evaluation.
This paper presents a practical procedure to evaluate and predict performance of horizontal wells. The procedure couples the analysis of pressure transient and rate-time data to enhance the reservoir-well description and accurately predict long-term performance of horizontal wells. The applicability of the procedure is demonstrated by several field examples.
Results from the field tests illustrate that inclusion of the rate-time data in pressure transient testing can be valuable to the design of a successful pressure test. Field examples of the design, planning, and tools used in the pressure tests are discussed. Rate-time data can also help improve the pressure match resulting in a comprehensive set of reservoir and well properties (vertical and horizontal permeabilities, well skin condition, effective well length, reservoir pressure, boundary effect, etc.) which enhances the reservoir-well description. This enhanced description can be used to realistically predict a well's long-term performance. Results indicate analytical solutions available in the literature can be used with care to perform the analysis. The application and limitations of the use of these models are discussed. Good agreement between model prediction and actual long-term well performance is shown.
Selective Tests in Horizontal Wells for a Better Reservoir Characterization
Authors: Lara A. Q. , Renard Gerard 
Published: December 2007

Abstract
Conventional pressure tests in horizontal wells present a lot of practical problems and interpretation difficulties. As a result, they are performed less and less often by oil companies.
In this paper a new procedure — pressure tests on limited lengths of horizontal wells — is proposed. It has some important advantages over conventional tests such as shorter duration and more reliable characterization of the major heterogeneities located near the well.
The need for good reservoir characterization is illustrated by a numerical example of a reservoir with a discontinuous shale lens located between the well and a bottom aquifer. First, we demonstrate that knowing some shale lens parameters such as the relative position of the shale may be very important to maximize well production. Then, we point out how these parameters can be obtained by selective tests conjugated with production logs performed at different times.
Finally, we discuss the advantages of the new procedure on a heterogeneous reservoir generated by stochastic simulation.
Cernent Resistivity and Implications for Measurement of Formation Resistivity Through Casing
Authors: Klein J. D. , Martin P. R. , Miller A. E. 
Published: December 2007

ABSTRACT
Measurement of formation resistivity through casing is an emerging logging technology, with prototype logging tools currently under development. Modeling studies show that the presence of cement could reduce the sensitivity of the TCRT™ (Through Casing Resistivity Tool™). Physically this tool has some similarity to a laterolog. Measurements would be seriously affected if the cement was much more resistive than the formation. We have carried out a laboratory study of cement resistivity with the funding from the Gas Research Institute. Our main objective was to provide hard data to use in assessing the impact of cement resistivity on measurements made with the TCRT™.
Our results show that cement resistivity is generally low, varying from less than 1 to 8 Ω-m at 120° F. Light-weight cements were generally the least resistive, with Class A, G and H cements more resistive. Resistivity was essentially independent of either confining or pore pressure. It was also independent of either current density or voltage. Cement resistivity appears to vary with temperature according to Arp's equation, as would be expected for nonconductive material saturated with water.
Thin sections and mercury injection capillary pressure data show that porosity in cement is dominantly microporosity, with pore throat diameter less than 0.1 microns. In addition helium porosity is high, ranging from 35 to 40%. The low observed resistivity is due to large amounts of water-filled microporosity.
The results of this study signify that the presence of cement will not seriously degrade measurements of resistivity through casing in many environments. Our work concentrated on cements normally used on the North Slope of Alaska, as well as Class H cement, a common Gulf Coast cement.
Potential applications of the TCRT™ include water flood monitoring at Prudhoe Bay and elsewhere, and detection of "missed pay" behind casing.
Well Test Analysis of Heterogeneous Reservoirs
Authors: Deng Xianfa , Home R. N. 
Published: December 2007

Abstract
The method of Green's functions has been a powerful tool to solve unsteady flow problems in homogeneous reservoirs. This paper extends the application of Green's function method to difFusivity problems in heterogeneous reservoirs. A basic formula is obtained for expressing in terms of Green's functions the general solution to the pressure equation with nonhomo-geneous initial and boundary conditions. Through some practical examples, appropriate methods are suggested to obtain the Green's function, which is more difficult to find in heterogeneous problems than in homogeneous ones. Reciprocity is a basic and useful property which facilitates our understanding of porous media flow problems. With the Green's function method developed, the conditions under which the Principle of Reciprocity holds in heterogeneous formation are studied. The application of the reciprocity principle to interference tests in heterogeneous reservoirs is discussed for practical cases.
Pressure-Transient Behavior of Reservoirs Forming a Pattern of Coupled Linear Segments
Authors: Larsen Leif 
Published: December 2007

ABSTRACT
Solutions and examples are presented for the pressure-transient behavior of wells producing from reservoirs made up of two or more coupled linear segments. The solutions are based on numerical shemes in terms of Laplace transforms of the pressure behavior of linear reservoirs.
The simplest cases considered consist of single self-intersecting linear reservoirs, and reservoirs formed as intersections of two and three linear reservoirs with identical properties. Generalizations to cases where each reservoir has its own properties is straightforward, only with more detailed input parameters.
General rectangular patterns of linear segments are also treated, with symmetric square patterns simplified to stepwise linear system.
Application of Fractal Reservoir Model for Interference Test Analysis in Kamojang Geothermal Field (Indonesia)
Authors: Aprilian Salis , Abdassah Doddy , Mucharam Leksono , Sumantri R. 
Published: December 2007

ABSTRACT
This paper presents the application of a new concept, i.e.; fractal model, to analyze pressure transient test data in complex naturally fractured geothermal reservoir.
Application of conventional type curves has been unsuccesful in analyzing and interpreting the interference test results in Kamojang geothermal reservoir which is considered as a complex naturally fractured system. Using the conventional type curve method, the pressure test data, in this case, can not match to the curve, primarily at early time data. The match, however, can be achieved by using the type curves generated based on "fractal reservoir model" which has been previously developed by Chang and Yortsos in 1990. Using the diffusivity equation of fractal reservoir, the equation for interference test has been derived and the result is then used for generating a new type curve method. In addition, the procedure to use this method has also been developed.
Using the generated type curves, application has been performed on analyzing the interference test data from Kamojang geothermal reservoir. The analyzing results demonstrate the viability of the model in describing characteristics of the reservoir such as transmissibility, storativity and fractal dimension of the medium.
Stochastic Relative Permeabilities Usually Have Neglectable Effect on Reservoir Performance
Authors: Tjølsen C. B. , Damsleth Eivind , Bu Tor 
Published: December 2007

Abstract
During the last couple of years Norsk Hydro has developed a 3D model for simultaneous generation of stochastic absolute and relative permeabilities.
By using core data containing relative permeability curves measured on a large number of core plugs from one single well in the North Sea, we have been able to model relative permeability curves (represented by endpoints and exponents) stochastically for four different depositional environments ranging from highly permeable mouthbar sands to low permeable tidal deposits.
We show that for all the depositional environments, stochastic variation of the relative permeabilities have only marginal, if any, effect on the production characteristic, compared to keeping the relative permeabilities constant at their mean.
Based on fractional flow theory, this paper summarizes the results from a theoretical and empirical statistical analysis of the correlation between the water shock front velocity and the absolute permeability for the different depositional environments, and we show that in specific cases this correlation can serve as an indication of the potential effects of stochastically varying relative permeability curves.
The main conclusion, which must be very comforting to practicing engineers, is that in some situations stochastic modeling of the relative permeability curves is of minor importance. However, the choice of mean relative permeabilities may be crucial.
Reservoir Description by Inverse Modeling: Application to EVGSAU Field
Authors: Sultan A. J. , Ouenes Ahmed , Weiss W. W. 
Published: December 2007

Abstract
The major problem of conventional geostatistical reservoir characterization by conditional simulation is that none of the equiprobable realizations (permeability and porosity) generated may fit the field data when used in a reservoir simulation. A recently developed inverse modeling procedure was tested on the CO2-foam pilot area of the East Vacuum Grayburg/San Andres Unit (EVGSAU). The modeling procedure estimated reservoir properties through an automatic and multi-well history matching algorithm. The reservoir parameters, which were estimated by solving an inverse problem, were permeability distribution, average relative permeability and capillary pressure curves, reservoir engineering parameters such as the productivity or injectivity index at the wells, and effective injection rates. All parameters were estimated at reservoir scale in this approach.
A least-square error objective function was minimized by using the simulated annealing method (SAM). The field data matched were the oil, gas, and water productions at each well. The convergence of this new algorithm is guaranteed by the use of SAM, and the permeability distribution generated is conditioned to the dynamic field data. Additionally, for the first time, reservoir engineering parameters were estimated at reservoir scale.
At each iteration, a limited number of reservoir parameters were adjusted. Then, a black oil reservoir simulator was used to evaluate the impact of these new parameters on the field production data. Finally, after comparing the simulated production curves to the field data, a decision was made to keep or reject the altered parameters tested.
A reliable, efficient computer code was developed to estimate reservoir properties by automatic history matching. The algorithm was tested on the EVGSAU for the waterflood period (1980–1985). After optimization, a good match was obtained for all the dynamic field data (production of oil, gas, and water) at all the wells located in the pilot area of the EVGSAU. The resulting large-scale reservoir description was then used to simulate CO2 injection after 1985. The pilot region production history from 1986–1991 was suitably matched using the waterflood reservoir description.
Vertical Interference Testing With a Wireline-Conveyed St raddle-Packer Tool
Authors: Pop J. J. , Badry R. A. , Morris C. W. , Wilkinson D. J. , Tottrup Peter , Jonas J. K. 
Published: December 2007

Abstract
A new approach to the in-situ determination of permeability, permeability anisotropy and lateral continuity of barriers to vertical fluid flow is introduced. The procedure employs a wireline-conveyed inflatable straddle-packer in conjunction with a vertically displaced pressure monitor probe to conduct vertical interference tests in openhole. The relatively large spacing between the packer interval and monitor probe (approximately 5 ft) results in a larger depth of investigation than is currently available with other wireline-conveyed tools. Multiple interference tests may be conducted during a single trip in the well.
The method of analysis is illustrated with data acquired in an oil well located in a complex, low-permeability, carbonate reservoir that has been under production for almost 40 years and under waterflood for approximately 30 years. As part of a field management program the operator wished to assess the status of pressure maintenance by means of a pressure survey and to measure the permeability anisotropy for use in subsequent numerical simulation work. Analysis of core data indicated that the permeability anisotropy should be low.
Feasibility of the testing procedure was established bearing in mind the restriction that flowrates would have to be limited during the pumping and sampling sequences to keep the test pressure above the bubble point pressure. Computer modelling and automatic parameter estimation techniques were employed to estimate the permeability and permeability anisotropy from the interference test data. Electrical and nuclear logs in conjunction with core photographs provided the means to establish the boundaries of the zones tested and to locate the major lithologic units. For comparison the pressure transients measured in the packer interval were analysed by established well testing methods.
A Mechanistic Approach to Understanding Wellbore Phase Redistribution
Authors: Hasan A. R. , Kabir C. S. 
Published: December 2007

ABSTRACT
Wellbore phase redistribution (WPR) frequently occurs during a shut-in test in wellbores having very compressible fluids, such as low-pressure, single-phase gas and high gas/liquid ratio multiphase fluid mixture, including steam. The consequence of WPR is a pressure buildup signature that deviates greatly from the commonly used constant-storage model, thereby precipitating test interpretation problems. A lack of physical understanding of the underlying process has led us to rely solely on empirical approaches — exponential and error function models — for analyzing field data. The existing methods have some drawbacks. For example, one may obtain nonunique results. Further, we cannot predict whether a particular well will exhibit WPR a priori. Thus, the available methods are restricted to the test analysis mode only.
In this work, we present a mechanistic approach to understanding the principal causes for WPR. A simple physical model, consisting of a liquid column and a small pocket of segregated gas at the top, is assumed to mimic a wellbore. The model well cannot receive any fluid from the reservoir upon shut-in; however, backflow from the wellbore into the reservoir is permitted to relieve excess pressure, generated by a rising bubble.
A mathematical model is developed for the idealized well by studying the rise velocity of a single bubble in the liquid column. Interestingly enough, a simplified analytical solution leads to an exponential form to describe the excess pressure behavior, caused by a single-bubble rise, as hypothesized by Fair. Thus, this work provides a basis for Fair’s intuitive exponential model.
The results show that both the wellhead and bottomhole pressures increase with elapsed time as a single gas bubble ascends up the liquid column. The magnitude of pressure rise is a strong function of flow impediment or skin in the wellbore vicinity, well diameter and its orientation, and wellhead pressure. A comparison of the simplified (exponential) and the rigorous solutions shows good agreement between the two at early times.
The proposed model provides a framework for understanding the physical mechanisms that underlie an anomalous pressure rise during a shut-in test. The model, although simplistic in nature, provides some justification for the use of existing empirical methods for interpreting field data.