bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reform and Privatization in the Hydrocarbon Sector
Authors: Khelil Chakib 
Published: December 2007

Abstract
Like in many other developing countries, Argentina, Bolivia and Peru formed state oil and gas companies to exploit their hydrocarbon resources. The government policy considered these resources part of the national patrimony and of great strategic importance in providing energy self sufficiency and fueling the country’s planned industrialization. Among other things, this policy provided a monopoly to state companies over many activities in the hydrocarbon sector, limited investments by private oil companies, restricted oil and petroleum products exports and imports and regulated crude oil and petroleum products prices and distribution margins. This policy had negative impacts on the state resources and debt. This paper presents the major transformations and privatization in the hydrocarbon sector that were recently achieved by Argentina and the outlook for Bolivia and Peru carrying out similar transformations. New hydrocarbon laws have been issued which did away with the state monopoly in the sector, provided major incentives for private investments and cleared the way for an open and competitive crude oil, natural gas and petroleum products markets. The passage of these laws paved the way for the privatization of state oil and gas companies Yacimientos Petroliferos Fiscales (YPF) and Gas del Estado (GdE) of Argentina. Soon Petroperu and YPF of Bolivia (YPFB) will be under the control of private investors. Argentina, Bolivia and Peru’s economies are showing revitalized growth and renewed interest by oil sector investors.
An Area of Review Variance Methodology
Authors: Warner D. L. , Koederitz L. F. , Dunn-Norman Shari , Laudon R. C. 
Published: December 2007

Abstract
When the Underground Injection Control (UIC) Regulations were promulgated in 1980, by the U.S. EPA, existing Class II (oilfield) injection wells operating at the time that the regulations became effective were excluded from Area of Review (AOR) requirements. EPA has expressed its intent to revise the regulations to include the requirement for AORs for such wells.
A Federal Adivisory Committee (FAC) has recommended that AORs for existing wells, not previously subject to that requirement, be performed within five years of promulgation of amended UIC regulations. The FAC has, however, recognized that conditions can exist that make it unnecessary to perform well-by-well AORs and that can allow wells in a basin, producing trend, region or field or a portion of such areas to be exempted from an AOR through a variance program.
A methodology for identifying areas that would be eligible for variance from AOR requirements has been developed. The methodology provides for evaluation of an area for variance based upon five criteria. These criteria could be used in any order, singly or in combination, to exclude some or all wells from the AOR process. Wells not excluded by variance would be subject to well-by-well AORs.
Seismic-Guided Estimation of Reservoir Properties
Authors: Schultz P. S. , Ronen Shuki , Hattori Masami , Mantran Pascal , Hoskins Josiah , Corbett Chip 
Published: December 2007

Abstract
When 3D seismic data and logs from multiple wells are available, maps of rock or reservoir properties for reservoir characterization can be improved in both detail and accuracy by using seismic attributes (mathematical transformations on the data) with log data in a statistical analysis, guided by principles of rock physics. A controlled study in a field with 3D seismic and 15 logged wells demonstrated both improved detail and improved accuracy in maps of effective porosity and water saturation.
Pressure Transient Testing of Horizontal Wells With an Overlying Gas Cap
Authors: Fleming C. H. , Perschke D. R. , Gilman J. R. , Kazemi Hossein 
Published: December 2007

ABSTRACT
This paper investigates pressure transient testing of horizontal drainholes in an oil reservoir with a large overlying gas cap. The study was prompted by the observation that many of the buildup tests obtained on horizontal drainholes exhibited large oscillations of the pressure derivative.
Results presented in this paper are based on both field data and numerical simulation. The main purpose was to determine the cause of the pressure derivative oscillations and to explore whether conventional analysis of buildup tests could yield reliable estimates of permeability and skin factor under existing field conditions.
Design and History Matching of a Very Large Waterflood/Miscible Gas Flood Model of the Northwest Fault Block, Prudhoe Bay, Alaska
Authors: Weiler Bruce E. , Saidikowski Ronald M. , Breit Vernon S. 
Published: December 2007

Abstract
Prudhoe Bay, located on Alaska’s North Slope, is the largest field discovered in North America. Over eight billion barrels of oil have been produced since the start of production in 1977. Four major waterflood/miscible water-alternating-gas (WAG) flood projects are in progress in the Prudhoe Bay field. This paper describes the construction of a model representing one of these projects using a combination of stochastic and deterministic tools, and input data from the major field owners (ARCO, BP and Exxon) by personnel from multiple companies. These techniques produced porosities and permeabilities that required only minor modifications to obtain an excellent history match for the Northwest Fault Block (NWFB) area of the Prudhoe Bay field.
The historical production period matched in this study included primary, secondary waterflood and tertiary miscible WAG flood mechanisms. During the history matching process, proper representation of the well’s perforation and wellwork history and the existence and extent of flow barriers (e.g. shales) were important to achieving a good match. Fluxes between the NWFB and the remainder of the field were a dominant force in some predictive cases, emphasizing the importance of field-wide reservoir management. The model demonstrated a close link between overall production and management of voidage replacement requiring a good balance between productivity gains associated with reservoir fracture treatments and injection rates.
PNC Log Evaluation in Gas-Filled Borehole Environments: A Case Study
Authors: Hashem M. N. , Gilchrist W. A. 
Published: December 2007

Abstract
This is a case study of Pulsed Neutron Capture (PNC) log evaluation in gas-filled environments. We describe the technique we have used to address the problem caused by the effect of gas-filled annuli on PNC logs in the Gulf of Mexico, south of the Mississippi River. Previous papers have considered the effect of various borehole environments, but none has addressed this specific problem. The PNC log is a key tool in reservoir management, surveillance, and depletion planning in the Gulf of Mexico. However, hydrocarbon saturations based on PNC surveys can be difficult to interpret due to borehole and diffusion effects on the capture cross section measurement, Σ. Although borehole and diffusion corrections are available for many cases, gas-filled annuli still present a significant problem. We have found a method for addressing this problem using the actual log data.
Ability of Geostatistical Simulations To Reproduce Geology: A Critical Evaluation
Authors: Hand J. L. , Yang Chung-Tien , Chopra A. K. , Moritz A. L. 
Published: December 2007

Abstract
Geostatistical techniques are being used increasingly to model reservoir heterogeneity on multiple scales. Several techniques are now available which differ in their underlying assumptions, complexity and applications. This paper compares the geostatistical sequential gaussian, sequential indicator, and truncated gaussian simulation techniques with the more traditional geological hand mapping description technique and compares their influence on flow simulation performance.
The base geological description was generated using a hand drawn map of the geological facies associations within a 3-D model area in a fluvio-deltaic environment. The average values of porosity and permeability were assigned to the respective facies associations. A second description was generated using sequential gaussian simulation by honoring the porosity and permeability well data, the corresponding vertical variograms, and the inferred lateral variograms. A third description was generated using sequential indicator simulation to distribute porosity and permeability instead of sequential gaussian simulation. Both of these simple geostatistical descriptions were not constrained by explicit geological facies association information. A final more complex geostatistical description was generated in which the underlying geological framework of facies association was first simulated using truncated gaussian simulation and then the porosity and permeability were distributed within each facies association using sequential gaussian simulation. All of the fine scale descriptions were compared in detail and scaled up to large grid blocks appropriate for flow simulation using a pressure solver.
A comparison of the 3-D hand drawn facies association map with the one computed using truncated gaussian simulation showed that the hand drawn map contained less variations than the geostatistical facies association map when conditioned to the same well data. Comparison of the fine scale porosity and permeability maps showed that the distribution of the average values of porosity and permeability in the 3-D hand drawn facies association map failed to reproduce the complex texture of the rocks giving a considerably more uniform distribution of these attributes. It was found that distributing porosity and permeability geostatistically without the influence of explicit facies association information significantly reduced the effective control on the distribution of these attributes, resulting in a more continuous distribution of porosity and permeability than that obtained when facies association information was used. Comparison of the fine scale permeability distributions to those obtained after scaleup showed that the pressure solver maintained the major permeability features apparent in the fine scale distribution which were important to reservoir performance. The influence of these description techniques on reservoir performance was compared using a fluid flow simulator.
Geostatistical Modelling of Heterogeneities in a Mixed Carbonate Platform: The Characterization of Complex Progradational and Retrogradational Mechanisms
Authors: Biver P. Y. A. , Norris R. J. , Vittori J. J-M. , Alabert F. G. 
Published: December 2007

ABSTRACT
In mixed carbonate siliciclastic platforms, deposition is strongly constrained by sea-level fluctuations which induces heterogeneities with complex lateral and vertical sequences. In such sequences, a logical scheme of deposition can be identified over several orders of cyclicity.
Although many geostatistical methods are available, very few are suitable to represent simultaneously the three main characteristics of such environments: the order of deposition, the evolution of facies proportions (lateral and vertical), and the correlation length of the facies. In this paper, we present a methodology well suited to reproduce those features; it is based on probability field simulation, facies are obtained by the truncation of a continuous random variable. The truncation thresholds are determined by indicator kriging.
The technique has been applied in a practical case: a recursive application of such a treatment allows the characterization of lithofacies and petrophysical classes, in consistency with the geological model and with the distributions of petrophysical parameters.
Subsequently, porosity values are assigned using a multiple sequential gaussian simulation which provides the appropriate porosity (ϕ) distribution for each petrophysical class.
Effective permeabilities (K) are then deduced from ϕ-Log(K) correlations which are different from one petrophysical class to another.
Finally, a sub seismic fracturation is roughly taken into account by a deterministic anisotropy factor on permeability. In addition, the main fracture axes are represented, after restoration of the actual geometry, using structural maps containing this information. The obtained reservoirs’ structure is therefore constrained by all the expected geological and petrophysical properties.
Field Results Of Injection Well Stimulation Treatments Using Micellar Dispersions
Authors: Moran J.P. , Maxwell W.N. 
Published: December 2007

Abstract
Use of micellar dispersions to increase water injection capacity of wells has grown rapidly during the past year. Treatments have been performed in many types of formations in nearly all oil-producing areas. The majority of these treatments have proved highly effective and economical. The purpose of this paper is to review the technology of stimulation with micellar dispersions, and compare theoretical results with those actually achieved. This analysis will attempt to show what factors might affect results, and determine where and how this type of treatment can be used most effectively.
Introduction
Injection well stimulation with micellar dispersions was first described by W. B. Gogarty, et al, in 1969. During the past year, this service has been commercially available and different types of formations in many areas have been treated by this process. The results of these treatments process. The results of these treatments (Table 1) indicate that micellar solutions can economically and successfully increase injectivity of water input wells. Analysis of the treatments has provided information which is useful in determining how and where these treatments might be used most effectively.
THEORY
Micellar solutions increase well receptivity to water by removing residual oil from the critical injection area around the wellbore. Removal of this irreducible oil saturation increases the relative permeability to water in the treated area. If all the oil is removed, relative permeability to water becomes equal to absolute permeability or single-phase flow.
Figure 1 is a plot of relative permeability to water and oil versus water permeability to water and oil versus water saturation. This is an actual plot of Bartlesville sand. The solid black lines represent actual plotted values. The dotted lines are extrapolated to show how relative permeabilities would change if varying permeabilities would change if varying percentages of residual oil were removed for percentages of residual oil were removed for the rock. Various formation cleaners and solvent systems are capable of relative permeability changes as indicated by the solid permeability changes as indicated by the solid lines, but only the micellar dispersions so far have been able to effect the changes represented by the dotted lines.
To show effect of the critical matrix on the overall injection rate, a formula can be developed using a cylinder (Fig. 2) where:
rw = well radius
rt = radius of treated matrix
Phase Behavior Impacts of Supercompressible Fluids on Pressure Transient Analyses
Authors: Beliveau Dennis , Fair P. S. 
Published: December 2007

ABSTRACT
Use of the real gas pseudopressure allows most gas well tests to be analyzed using techniques developed for the ideal slightly-compressible fluid problem. However, at near-critical conditions (ie. Tr &lt; 1.1), fluids show dramatic changes in density, viscosity, and isothermal compressibility. The pressure transient behavior of these fluids is not duplicated by the pseudopressure approximation; this requires solution of the nonlinear problem.
Use of Pressure Transient Data To Obtain Geostatistical Parameters for Reservoir Characterization
Authors: Yadavalle S. K. , Roadifer R. D. , Jones J. R. , Yen Nai-Shyong 
Published: December 2007

Abstract
Recent interest1,2,3 in the use of pressure transient data in the area of geostatistical reservoir description has focused on constraining permeability realizations to well test derived average permeabilities or to the measured pressure response. These methods assume an a priori knowledge of the horizontal variogram. Such information is difficult to obtain from the common sources of well data (cores and logs) particularly at the small lag values which can dominate the information in a well test. In this paper we investigate the possibility of deriving an estimate of the horizontal variogram directly from well test data. We also present information on the significance of average permeability values derived from well test information.
Our results indicate that well test average permeabilities, kwt, are not generally a good approximation of the average of the underlying permeability field even if the field is completely random. In the correlated cases, the relationship of the well test derived average and the distribution average is heavily realization dependent. With respect to variograms, we find that our methods produce a reasonable estimate of range and short-lag shape when kwt/kgm for the correlated case compares favorably with the value derived from the uncorrected case with the same level of variability. No estimate of input values of nugget or sill can be derived using the approach presented here.
Real Time Pressure Transient Analysis Methods Applied to Wireline Formation Test Data
Authors: Proett Mark A. , Waid Margaret C. , Kessler Calvin 
Published: December 2007

Abstract
The primary objective of wireline formation testing is to estimate formation pressure and permeability from short duration transient well tests. This paper demonstrates new real time pressure transient analysis methods which may be used during testing to estimate permeability and pressure. These new plots may also be used to determine when sufficient data has been acquired for accurate pressure and permeability determination. Additionally, for tight zones with permeability less than 1 millidarcy, new methods and special plots are presented for interpretation of real time data obtained during the initial drawdown and buildup times. For tight zones the early time data may be distorted by flowline storage effects and is normally ignored by traditional well test analysis techniques. New methods are given in this paper for estimating the compressibility of the actual fluid within the flowlines and chambers of the tester during each test, and this value for compressibility is used in each real time model.
A full 3D finite element near wellbore simulator (NEWS†) that represents an exact solution is used to show that these new plots give the same values of permeability and pressure as would be obtained from very long buildup times using conventional analysis methods. The tight zone analysis substantially reduces the time required to test tight formations and utilizes data obtained within the optimal dynamic range of pressure transducers.
Gas Optimization at the Kuparuk River Field
Authors: Stoisits R. F. , Scherer P. W. , Schmidt S. E. 
Published: December 2007

Abstract
The Kuparuk River Field is located on the North Slope of Alaska, original oil in place was approximately 6.4 billion barrels of oil. Total cumulative production to date is approximately 1.2 billion barrels, and current average daily production is 300,000 barrels of oil. The total number of wells in the field is 750, approximately half of these are producers and half are injectors. A number of enhanced recovery processes including; waterflood, water alternating immiscible gas, and water alternating miscible gas are underway.
Oil, water, and gas are separated at three Central Processing Facilities (CPFs). Production can be routed between the various CPFs to more efficiently utilize facility processing capacity. Gas is compressed at each facility for use in gas lift operations and for miscible and immiscible water alternating gas pressure support projects. Currently the central processing facilities are gas handling limited; therefore, a gas optimization strategy is vital to the efficient operation of the field.
The objective of the optimization strategy is to maximize oil production by; efficient allocation of lift gas to the producing wells, non-gas lifted production well selection, allocation of production to the various CPFs, load balancing between centrifugal and reciprocal compressors. If Kuparuk had no compression limitations then all wells would be on production and all gas lifted wells would be operated at maximum rate. The limited compression capacity requires Kuparuk to optimize formation gas and recycled lift gas in order to optimize field oil production.
A computer program has been developed to facilitate optimization. This program may be run in lift gas allocation and production well selection mode or in system analysis mode. In the lift gas allocation/producer well selection mode, lift gas rates for wells are determined based on the facility incremental gas oil ratio (IGOR), for a given set of facility operating conditions. The formation gas oil ratio (FGOR) cutoff for wells not on gas lift is set at the IGOR. These two criteria provide starting points for the optimization. The program then performs an iterative search technique to converge on the optimum IGOR and FGOR for each CPF. In the system analysis mode, thousands of simulations are run to explore the system response to a variety of operating conditions. Optimal facility operating parameters are determined from the result of the system analysis simulations.
The lift gas allocation/producing well selection processing is done on the field data acquisition system, and the system analysis simulations are implemented via parallel distributed processing on a network of workstations. Surface line hydraulics effects are modeled using nonlinear adaptive models (neural nets) based on rigorous hydraulic simulations. The distributed processing and adaptive models implementation minimizes processing time and cost.
Prediction of Formation Damage Due to Suspended Solids: Modeling Approach of Filter Cake Buildup in Injectors
Authors: Khatib Z. I. 
Published: December 2007

ABSTRACT
Solid particles in injection water build up a filter cake when intercepted on the face of the formation matrix, in the perforations, or even in the gravel pack. The effect of applied pressure, solids type, and oil presence on the porosity and permeability of these thin cakes was determined using a compression–permeability cell. The solids investigated were iron sulfide, iron hydroxide, iron hydroxide/bentonite mixture, calcium carbonate, calcium sulfate, and produced silt and clay. Empirical correlations between permeability and porosity were determined and used to predict injectivity decline rate under reservoir conditions for four common well completions.
A new model for calculating the combined matrix and filter cake resistances in perforations and fractures was developed by using the electrical circuit analog theory.
The results of this study and an earlier study1 were implemented in a user-friendly PC program. This program predicts matrix damage and the injectivity decline rate as a function of solids properties. Consequently, filtration requirements and/or well stimulation schedules can be determined.