bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effect of an Invaded Zone on Pressure Transient Data from Multi-Probe and Packer-Probe Wireline Formation Testers in Single and Multilayer Systems
Authors: Gok I. M. , Onur M. , Hegeman P. S. , Kuchuk F. J. 
Published: December 2007

AbstractA three-dimensional r-θ-z single-phase fully-implicit finite-difference model for a vertical well has been developed to examine how the presence of invaded zones affects the multiprobe and packer-probe pressure measurements in single-layer and multilayer (crossflow) systems. Invasion zones are modeled as composite zones concentric with the wellbore, that have different rock and fluid properties (permeability, porosity, viscosity and compressibility) from those of the native uninvaded formation.The results show that for multi-probe wireline testers, the sink (or the flowing) and horizontal probe pressure responses are highly affected by the invaded region properties, while the vertical probe pressures are mainly influenced by the properties of the uninvaded zones. For packer-probe testers, similar results are obtained; i.e., the vertical probe pressures are mainly influenced by the properties of the uninvaded zones, while the packer interval pressures at early times are influenced by the invaded zone properties. It is shown that if the invaded zones are incorporated into the interpretation process using the model developed in this work, simultaneous matching of spatially available wireline formation tester pressure data sets using nonlinear regression can provide estimates of both invaded and uninvaded zones parameters. A synthetic example of a multi-probe test is presented to confirm the theory and procedures developed in this work.
Multilayer Modeling to Define a Fluvial Sandstone Reservoir's Dynamic Structure Using Multistation Multiprobe Formation Tester Measurements
Authors: Domzalski S. , Pop J. J. , Boydell W. G. , Hadbi A. 
Published: December 2007

Abstract
Fluvial sandstone reservoirs display stratification and laminations which can critically affect vertical, thus horizontal, fluid movement in the reservoir during production. Understanding and quantifying in-situ permeability anisotropy and its vertical distribution, the dynamic structure of the reservoir, will dictate decisions on well construction, well completion and spacing and water and/or gas injection schemes that will ultimately impact the overall success of a field's development.
This paper looks at the application of single and multilayer transient interpretation models to multistation multiprobe formation tester measurements in order to assist in the definition of the dynamic structure of a fluvial sandstone reservoir. The common volume of the formation investigated by several of the tests afforded the opportunity to compare the predicitions of various formation models.
The paper is an extension of a case history8 from an Algerian fluvial sandstone oil-bearing reservoir where near to 60 in-situ measurements of permeability anisotropy, Kv /Kh, were obtained by running vertical interference tests (VITs) with a multiprobe formation tester during openhole (OH) logging operations. The formation tester, configured with four probes and a recyclable constant rate flow module, was used to perform, on average, 10 VITs per well for several key wells in the field. The spatial arrangement of the probes employed when set against the wellbore at each test station allowed simultaneous, overlapping measurements of permeability anisotropy to be performed on 0.70 meter and 3 meter length scales (the latter dimension being similar to vertical grid block sizes used in field reservoir simulators). These measurements provided Kv / Kh ratios in homogeneous "clean" sections of the sedimentary units investigated and information on sealing properties of tight streaks, shales, laminations and "dirty" sections straddled by the probes through the determination of the "effective" values of Kv / Kh.
The paper considers an llmeter lithological unit, within a 60 meter reservoir section, from one well where four stations were tested with the multiprobe formation tester. (The complete logging operation consisted of 10 stations over the 50 meters of net pay.) The llmeter lithological unit is made up of "clean" sandstone layers interspersed with "dirty" sections and high density "tight" streaks. Multilayer (crossflow-layered) pressure transient interpretation was applied to the data acquired with the multiprobe formation tester (four stations), incorporating single layer interpretation results as well as measured petrophysical and geological data. A simple limited-extent permeability barrier model also assisted in better understanding the lateral extent of a hydraulically semi sealing "streak". The results derived from these more complex analyses are compared to the "equivalent" single layer interpretation results.
The Reduction of Near Zone Effects on the Multi-component Induction Logging Tool
Authors: Yu Liming , Rabinovich Michael , Tabarovsky Lev , Wang Tshili 
Published: December 2007

Abstract
The multi-component induction tool (3DEX) developed by Baker Atlas is comprised of three mutually orthogonal transmitter-receiver pairs measuring the secondary magnetic field at ten different frequencies. The measured data include the conventional coaxial component, Hzz, parallel to the borehole axis, and two coplanar components, Hxx and Hyy, perpendicular to the wellbore. In addition, two crosscomponents, Hxy and Hxz, are acquired to determine the formation dip and azimuth angles. The objective of this tool is to derive the horizontal and vertical resistivities of thinly laminated sand/shale sequences and anisotropic sands.
The tool responses are influenced by near zone anomalies, such as drilling mud, elliptic invasion, drilling induced fracture, and tool eccentricity. Because the tool uses a relatively large transmitter-receiver separation, the near zone effects are fairly small on the coaxial component, Hzz, but they remain strong on the coplanar components, Hxx and Hyy.
To reduce the near zone effects, a multi-frequency data processing technique was developed. We validated the technique with synthetic data produced by both 2-D and 3-D modeling algorithms. In an example of the borehole effect, the relative difference in responses with and without the borehole is 22% in the single frequency data but only 0.1% in the multifrequency processed data. In an example of the eccentricity effect, the relative difference in responses with and without tool centralization is 213% in the single frequency data but reduced to only 0.3% in the multi-frequency processed data. Therefore, after the multi-frequency data processing, a simple 1-D vertically layered model can be utilized for data interpretation because much of the near zone effects have been removed. The applicability of the MFF technique is limited in highly resistive formations due to a decreased signal-to-noise ratio as a result of the hardware noise.
The United Nations Framework Classification for World Petroleum Resources
Authors: Ahlbrandt T. S. , Blystad P. , Young E. D. , Slavov S. , Heiberg S. 
Published: December 2007

Abstract
The United Nations has developed an international framework classification for solid fuels and minerals (UNFC). This is now being extended to petroleum by building on the joint classification of the Society of Petroleum Engineers (SPE), the World Petroleum Congresses (WPC) and the American Association of Petroleum Geologists (AAPG).
The UNFC is a 3-dimansional classification. This: Is necessary in order to migrate accounts of resource quantities that are developed on one or two of the axes to the common basis;Provides for more precise reporting and analysis. This is particularly useful in analyses of contingent resources.
The characteristics of the SPE/WPC/AAPG classification has been preserved and enhanced to facilitate improved international and national petroleum resource management, corporate business process management and financial reporting.
A UN intergovernmental committee responsible for extending the UNFC to extractive energy resources (coal, petroleum and uranium) will meet in Geneva on October 30th and 31st to review experiences gained and comments received during 2003. A recommended classification will then be delivered for consideration to the United Nations through the Committee on Sustainable Energy of the Economic Commission for Europe (UN ECE).
Significant Differences in Proved Reserves Volumes Estimated Using SPE/WPC Reserves Compared to United States Securities and Exchange Commission SEC Definitions
Authors: Harrell D. R. , Gardner T. L. 
Published: December 2007

Abstract
A casual reading of the SPE/WPC Petroleum Reserves Definitions (1997) and the U.S. SEC definitions (1978) would suggest very little, if any, differences in the quantities of hydrocarbon reserves estimated under those two classification systems. The differences in many circumstances for both volumetric and performance-based estimates may be small.
In 1999, the SEC began to increase is review and en-forcement process, seeking greater understanding and compliance with its oil and gas reserves reporting requirements. The agency's definitions were promulgated in 1978 in connection with the Energy Policy and Conservation Act of 1975 and at a time when most publicly owned oil and gas companies and their reserves were located in the United States. Oil and gas prices were relatively stable and virtually all natural gas was marketed through long-term contracts at fixed or determinable prices. Development drilling was subject to well-spacing regulations as established through field rules set by state agencies.
Reservoir evaluation technology has advanced far beyond that used in 1978; production-sharing contracts were uncommon then and probabilistic reserves assessment was not widely recognized or appreciated in the U.S. All of these factors plus numerous other considerations continue to create continuing unsolved problems in adapting the application of 1978 vintage definitions to the technological realities of 2003, particularly in light of the business and economic climate in the U.S. and around the world.
This paper presents several real-world examples of how the SEC engineering staff has updated its approach to reserves assessment as well as numerous remaining, unresolved areas of concern. These remaining issues are important, can lead to significant differences in reported quantities and values and may result in questions about the "full disclosure" obligations to the SEC.
Horizontal Openhole Gravel Packing in a Depleted and Heterogeneous Reservoir
Authors: Onwusiri Henry , Onwuzurike Chiji , McPike Tim , Jansen Rene 
Published: December 2007

Abstract
Open-hole gravel packing in vertical/conventional wells is an accepted sand exclusion method that has not gained wide and rapid application in horizontal wells. The reason is largely due to sand placement challenges in the horizontal drain that could lead to premature sand screen-out. Consequently, many operators are skeptical gravel packing horizontal wells since failure could probably result in enormous capital risk. In the Niger Delta, about 70 % of the hydrocarbon-bearing reserves lie in shallow unconsolidated reservoirs where the sonic transit time vary between 110 to 140 us/ft. Production from these intervals has proven record of sand threats to operating cost, well integrity, surface facilities and production sustenance. The challenge is to complete wells in these reservoirs with sand exclusion materials that would guarantee full life-cycle production performance.
Early horizontal wells in the region were completed with stand-alone screens, but recently, the expandable sand screen (ESS) took a leading edge. Though the ESS has a higher inflow area compared to other screens, its high cost, lack of full-bore expansion and the required lead-time continue to raise concerns especially when considered for applications in brown field development where well potential and reserve rewards are low. In response to these concerns, in 2002, openhole gravel packing (OHGP) in a horizontal well was investigated and considered as an alternative sand exclusion option in Shell Petroleum Development Company (SPDC). The trial candidate, the Obigbo-North QWSB-3 was selected and successfully completed as the first horizontal OHGP in SPDC using the alpha-beta wave concept.
Based on simulation results, about 9237 lbm of sand was planned for placement in 1000-ft of 6.0-in hole size, however, the actual sand pumped was about 10830 lbm. This represents an estimate of 6.25-in drain hole size. The application saved over $0.3 million when compared to the cost of using ESS. For the Eastern asset team that drills an average of 12 wells annually, an annual projected completion cost-saving of some $3.6 million is achievable.
Based on the initial production testing, Obigbo-North Well QWSB-3 tested 3250 BOPD with a productivity index (PI) of 130 bbl/(psi-D). Baseline Memory Production Logging Tool (MPLT) logging showed that the entire drain section completed on the clean sand member had effective inflow into the linerbore. In addition to establishing confidence in the application and performance efficacy of OHGP, this trial and the significant cost-savings will engender a paradigm shift to horizontal well sand control. In this presentation, we will share some data and results based on field experiences, challenges and new understanding.
Compositional Modeling of Gas Injection With Three Hydrocarbon Phases for Schrader Bluff EOR
Authors: Wang Yun , Lin Cheng-Yuan , Bidinger Curt , Muralidharan Venkataramanan , Lee Sheng-Tai 
Published: December 2007

Abstract
A comprehensive analysis of Schrader Bluff viscous oil EOR performance is presented in this paper using the newly developed three-hydrocarbon-phase (3 HC) compositional table look-up approach. The unique combination of viscous oil, low reservoir temperature and high level of CO2 in the miscible injectant (MI) gives rise to the formation of 3 HC phases in the field operating pressure range for the Schrader Bluff EOR processes in Alaska. The numerical difficulties associated with the presence of 3 HC phases are well documented in the literature. A new 3 HC-phase compositional table look-up option within a commercial compositional simulator was developed to cope with these numerical difficulties. The application of this new approach in the Schrader Bluff EOR evaluation serves as the first field-scale validation of such approach. The analysis presented in this paper contains three parts. First, 1D slimtube models are built using both a 3 HC-phase slimtube simulator and the compositional table look-up option to validate the new approach. Then a 2D well-pair model is constructed to investigate the effect of gravity segregation. Optimal vertical gridding and WAG schedule are determined as a result of the 2D analysis. Finally, a 3D field-scale pad model is used to predict the EOR performance. In addition, a simplified methodology is developed to calculate the returned MI production for Schrader Bluff. The 3D results show that the 3 HC-phase compositional look-up methodology can be applied to field-scale processes for which other approaches for handling 3 HC-phase flow are either numerically unstable or too time consuming.
Horizontal Well Design Optimization: A Study of the Parameters Affecting the Productivity and Flux Distribution of a Horizontal Well
Authors: Vicente Ronaldo , Sarica Cem , Ertekin Turgay 
Published: December 2007

Abstract
With the widespread applications of horizontal wells and its successful performance in the last decade, a number of relevant questions has been raised with respect to the optimization of horizontal well design. Considering the high costs involved and the technical challenges that are faced by the industry under various scenarios such as offshore environment, unconsolidated sands and heavy oil production, questions related to the optimization protocols to be followed have become progressively more important and more difficult to answer. Thus, the task of optimizing horizontal well design requires an investigation of the parameters that affect the productivity and ultimately the behavior of both reservoir and horizontal well domains, as well as the risks and costs involved in each alternative.
Based on a fully implicit, three-dimensional numerical model coupling reservoir and horizontal well flow dynamics, a detailed study of the parameters that affect the behavior of flux distribution and productivity along horizontal wells has been performed. The parameters analyzed include permeability, initial gas saturation, anisotropy ratio, well location, fluid viscosity, flow rate, well length, and well diameter. A tool that permits to compare and select the potential options in terms of the gain in productivity per additional unit of well length and diameter is also introduced.
Validation of the numerical model used in this study is performed using production-logging data and the examples of results of the application of the optimization protocol developed are reported for some of the Petrobras offshore fields.
Experimental and Simulation Studies of Steam-Propane Injection for the Hamaca and Duri Fields
Authors: Mamora D. D. , Rivero J. A. , Hendroyono A. , Venturini G. J. 
Published: December 2007

Abstract
Studies have been conducted to evaluate the feasibility of steam-propane injection for the Hamaca heavy oilfield (8°API) and for the Duri intermediate oilfield (20°API). The experiments involved injecting steam simultaneously with propane at the top of a vertical cell containing a mixture of sand, oil and water. Superheated steam was injected at 170°C and 3.5 ml/min (Hamaca) and 260°C and 5.5 ml/min (Duri), with the cell outlet pressure at 50 psig (Hamaca) and 500 psig (Duri). Runs were made with propane:steam mass ratios (PSR's) ranging from 0:100 to 10:100. With steam-propane injection (PSR 0.05): (i) start of oil production is accelerated by 23% (Hamaca) and 30% (Duri), (ii) steam injectivity is up to three times higher, and (iii) steam front velocity is higher, indicating greater partitioning of the distilled fractions into the propane stream that appears to act as an efficient carrier gas.
A simulation study was conducted using a 1D 48 grid-cell model with a ten pseudo-component oil model for the Hamaca oil. Satisfactory history matches of the experimental runs were obtained; C7 – C10 appear to play a significant role during steam-propane injection. A reservoir simulation study was performed using a 9 × 5 × 10 3D Cartesian model representing one-eighth of a 10-acre 5-spot pattern. Five-year forecast runs were made with well steam injection rate of 600 BPDCWE. Production is enhanced with steam-propane injection (PSR0.05) as follows: (i) start of oil production is accelerated by 20%, (ii) oil production peak with steam-propane injection (1100 STB/D) is significantly higher than that with pure steam injection (690 STB/D), (iii) oil production acceleration increases with propane content, (iv) oil recovery is about three times that with pure steam injection, indicating improved sweep/displacement efficiency with steam-propane injection.
Enzyme Breaker Technologies: A Decade of Improved Well Stimulation
Authors: Brannon Harold D. , Tjon-Joe-Pin Robert M. , Carman Paul S. , Wood William D. 
Published: December 2007

Abstract
Fracturing fluids are most commonly aqueous systems comprising various polymers and crosslinking agents added to facilitate effective proppant transport and placement. A goal of fracturing practitioners has been to apply breaker technologies effective to eliminate or minimize the residual gel damage left behind by such systems in order to optimize the well stimulation. As a result of R&D efforts to that end, polymer-linkage-specific (polymer-specific) enzyme breakers were first introduced for fracturing applications in 1992. To date, these enzyme breakers have been employed in thousands of fracturing treatments around the world. Recent case studies evaluating long-term cumulative production have shown that wells in which polymer specific enzyme breakers have been applied demonstrate extraordinary performance when compared to production from offsets using other technologies. The long-term success of polymer-specific enzymes in fracturing operations for improving long-term production has been predicated upon a number of characteristics unique to enzymes, including their specificity to target polymer linkages and their functionality as catalysts which are not "spent" in the reactions they initiate. Additionally, contrary to popular misinformation, enzymes are effective at extremes of pH and temperature when properly applied. These unique properties are thought to make polymer-specific enzymes the polymer-degradation additive, which would produce the most effective proppant pack, thereby maximizing long-term productivity.
The numerous case histories and offset comparisons documented in previous studies were, as a rule, relatively short-term in the prospective life of a well. The current endeavor seeks to provide detailed follow-up analyses of truly long-term production data from 170 fracture stimulated wells in the Canyon Sand, Penn, Lobo-Wilcox, Redfork, Hosston, and Grayburg/SanAndres formations and, the deep McKittrick field. Production histories over periods of up to 8 years were evaluated on wells treated with the polymer-specific enzymes and compared to offsets completed using conventional breaker technologies. The results clearly demonstrate the benefits of application of polymer-specific enzyme breakers on long-term well productivity.
On Reservoir Fluid-ow Control with Smart Completions
Authors: Ramakrishnan T. S. 
Published: December 2007

Abstract
Poor displacement efficiency in hydrocarbon formations is often due to the natural variation in the mobility of fluids across the reservoir strata. Historically, completions with cemented casing, packers, and selective perforations have been used to mitigate the disparities in water encroachment over the reservoir interval. Recently, completion technologies using downhole valves allowing production and injection control over multiple zones have become available. The central idea is that the downhole control may be used to adjust flow distributions along the wellbore to correct undesired fluid-front movement.
In this paper, we address several technical issues related to downhole controls. We consider the completion, the reservoir, the measurement, and the feedback algorithm that adjusts flow-control devices as a single system with quantitative models for each of the components. Both pressure and flow-rate control systems are discussed. Downhole control is modeled for electrical, reversible hydraulic and unidirectional hydraulic valves. System design requires a quantitative description of both the orifices in the control valves, and the feedback control algorithm. The design methodology for different valve systems is described and the disadvantages of hydraulic systems are discussed. In particular, it is shown that in conjunction with an automated feedback control, hydraulic valves will oscillate. Computations also show that all other factors remaining equal, these oscillations occur most easily in low permeability zones. We also illustrate novel anticipatory control algorithms that prevent overshooting with unidirectional hydraulic valves.
For layered systems that communicate, a front movement equation is derived using perturbation techniques. This technique provides the zone of influence of wellbore flow control devices, and illustrates the maximal benefit that may be obtained through downhole control, and hence provides a ready comparison of the benefit with completion costs.