bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Computerized System for Planning Major Investment Decisions in Oil
Authors: Dougherty E.L. , Thurnau D.H. 
Published: December 2007

Abstract
A mathematical model, based on a systems approach, has been developed and is being used as a primary tool in planning investments in oil field production facilities. For a given set of assumptions the model determines magnitude and timing of investments in primary and secondary wells, surface-handling facilities and pipelines, and fixes production rates each time period to maximize present worth profit over a planning horizon. Engineering profit over a planning horizon. Engineering requirements, economic factors plus physical and regulatory limitations are simultaneously taken into account. The model
generates better plans than conventional procedures, helps systematize and document basic planning data for later reference or updating, and provides a unique common ground which provides a unique common ground which promotes understanding and communication promotes understanding and communication between engineers, planners and top management.
Introduction
In all business enterprises, some form of planning takes place, although the quantity and planning takes place, although the quantity and quality may vary widely depending upon the nature of the business and the attitude and level of sophistication of the management. Since the petroleum industry has long been a leader in petroleum industry has long been a leader in applying latest technology to improve operations it is no surprise that petroleum companies have been among the first to begin applying modern computer-based management methods to their critical planning problems.
The greatest advantage to be gained from applying the computer in a planning situation is to provide a mechanism by which data and assumptions can be easily and quickly converted into meaningful planning guidelines. With an efficient and flexible system, it is possible to feed in new data as soon as it becomes available to keep planning current.
From a technical standpoint, the oil business gives rise to some of the most difficult analytical planning problems encountered in business. As a result, progress toward development of improved computerized planning systems for the petroleum industry has come slowly. However, recent mathematical developments combined with the ability of modern day computers to process enormous quantities of data at fantastic speeds now makes it possible to consider all significant interactions in a complex oil system in generating the kind of information required by enlightened petroleum managements to make better decisions.
Of course, the core of these planning problems is economic evaluation for problems is economic evaluation for decision-making.
Analysis of Coal Gas Reservoir Interference and Cavity Well Tests
Authors: Mavor M. J. , Robinson J. R. 
Published: December 2007

Abstract
This paper discusses the analyses of transient pressure data that has been measured during single well test and multi-well interference tests performed in wells producing gas and water from coal seams of the Fruitland Formation of the San Juan Basin of Colorado. The test procedures included open hole drill stem tests, cased hole water injection tests, open hole production tests, multi-well interference tests, and post-cavitation production and shut-in tests. Proper evaluation of the pressure behavior measured during each type of test resulted in similar estimates of the absolute permeability of the coal gas reservoir natural fracture system.
Evaluation of post-cavitation well test data has not been presented in the literature prior to this paper. The analysis results are shown to be accurate by agreement with reservoir simulation and multi-phase interference test analysis results.
Analysis of the Hydraulic Fracturing Behavior in the Bowen Basin
Authors: Morales R. H. , Davidson S. C. 
Published: December 2007

ABSTRACT
This paper presents an analysis of the hydraulic-fracturing stimulations of the coalbed formations of the Bowen Basin of eastern Australia. In particular, two fracturing tests conducted in coal seam No. 4 (Well 3) are analyzed.
The analysis indicates that multiple fractures with horizontal and vertical components are created. A pressure-dependent fluid-loss formulation for naturally fractured reservoirs and a large apparent fracture toughness are necessary to match the observed pressures.
A calibration treatment to determine the fracturing regimes, pressure-dependent permeability, and apparent fracture toughness is proposed for the design and analysis of forthcoming fracturing stimulations. The formulations for these mechanisms are described.
Liner Cementing Across the Wasatch Formation in the Bluebell Altamont Field: A Case Study
Authors: Grubich J. M. , Morris B. V. , Gill P. J. 
Published: December 2007

Abstract
This paper describes work done in the Bluebell Altamont Field of Northeastern Utah (see fig. 1), with the objective of eliminating poor bonding on liners set in the Wasatch Formation. The Wasatch Formation has posed problems with cementing, as well as drilling, due to the frequency of natural fractures in the zone [2]. The use of Anionic Aromatic Polymers in cement systems has proven to exhibit superior fluid properties that enable the cementing of liners with low pipe to open hole tolerances. The cement systems have also provided improved cement bonding across the Wasatch Formation.
New Type Curves for Analyzing the Transition Time Data from Naturally Fractured Reservoirs
Authors: Onur Mustafa , Satman Abdurrahman , Reynolds A. C. 
Published: December 2007

Abstract
This work presents new type curves for the characterization of a naturally-fractured (dual-porosity) reservoir. These type curves were motivated by new approximate solutions for the pressure derivative which apply during the transitional flow period which exists between the two classical semilog straight lines. These approximate solutions suggest the appropriate pressure, pressure-derivative, integral-pressure-derivative and time groups necessary to prepare type curves. New type curves are presented for both the pseudosteady-state interporosity flow model of Warren and Root and the transient interporosity flow model of Kazemi and de Swaan.
Transient Finite Element Code: A Versatile Tool for Well Performance Analyses
Authors: Morita Nobuo 
Published: December 2007

ABSTRACT
This paper describes a system of general transient finite element flow programs for analyzing complex flow problems. It emphasizes a structured system consisting of a set of mesh generators, a main program, and a post processor, allowing applications as a routine practical tool rather than a research tool for well performance analysis, completion design tool, and pressure transient analysis.
Using Polymer Injectivity Tests to Estimate Fracture Porosity in Naturally Fractured Reservoirs
Authors: Gilman J. R. , Hinchman S. B. , Svaldi M. A. 
Published: December 2007

ABSTRACT
A new technique is presented to calculate fracture porosity in naturally fractured reservoirs using composite system analyses.
The concept outlined here is to inject a viscous solution (e.g. polymer) which will not invade the matrix rock, but remains in the fractures. Subsequent falloff tests can then be used to determine the bank radius of the polymer in the fractures and thus fracture porosity from material balance. In the early 1980's Marathon Oil Company performed a number of polymer injectivity tests in naturally fractured reservoirs. In several cases, apparent bank radius was much larger than anticipated. This observation lead to the technique proposed in this paper.
Three-Dimensional Analysis and Visualization of the Wellbore and the Fracturing Process in Inclined Wells
Authors: Morales R. H. , Brady B. H. , Ingraffea A. R. 
Published: December 2007

ABSTRACT
This paper describes the three-dimensional analysis and visualization of an inclined wellbore during the early stages of the hydraulic fracturing process. The analysis indicates that two or more fractures are developed during the early stages of pumping. Depending on the well inclination, these fractures can be aliped with or intercept the wellbore axis. Further, the fractures interact, twist and turn to align parallel to the preferred fracture plane. Based on this analysis, guidelines for perforation completions are proposed.
Field Implementation of Proppant Slugs to Avoid Premature Screen-Out of Hydraulic Fractures with Adequate Proppant Concentration
Authors: Cleary M. P. , Johnson D. E. , Kogsbøll H-H. , Owens K. A. , Perry K. F. , de Pater C. J. , Stachel Alfred , Schmidt Holger , Tambini Mauro 
Published: December 2007

ABSTRACT
Premature screen-outs and/or low proppant concentration are the most likely cause of failure in hydraulic fracturing treatments. Although commonly blamed on a variety of presumed problems—most typically the treating fluid, or large-scale reservoir conditions, such as permeability or stress profile—the true source of most problems has been uncovered only recently by careful analysis of treatment data. The source is referred to as near-wellbore tortuosity, but it can variously arise from deviatoric stress, natural fractures and/or perforation-dominated creation of complex fracture patterns in the wellbore vicinity.
Numerous theories have been formulated to deal with near-wellbore screen-outs and, especially for oriented wellbores from Arctic or offshore platforms, various perforation strategies have been postulated and/or implemented. In contrast to the idealizations and costs associated with those theories and strategies, this paper presents simple cheap solutions that are less sensitive to the wellbore environment This novel strategy involves injection of proppant slugs into the near-wellbore region and, when necessary, immediate shut-ins upon small slugs, with three important results: the response of the near well-bore region can be measured and characterized; a large part of the near-wellbore tortuosity can be removed, by simplifying the near-wellbore fracture pattern; and the true nature of the large-scale reservoir response can be determined, e.g. from the greatly modified pressure fall-off obtained after placing slugs near the wellbore.
The paper reports the concept and implementation, in a number of commercial fracturing environments, in both gas and oil reservoirs, with both foam and liquid-gel jobs. These show the effective removal of tortuosity varying from 20 to 200 bars and associated elevation of allowable proppant concentrations.
Natural Fractures in Sonora Canyon Sandstones, Sonora and Sawyer Fields, Sutton County, Texas
Authors: Marin B. A. , Gift S. J. , Hamlin H. S. , Laubach S. E. 
Published: December 2007

ABSTRACT
The Sonora Canyon is one of several "Canyon Sands" (Virgilian-Wolfcampian) intervals that exist in the Val Verde Basin of southwest Texas. This paper describes the presence and attributes of natural fractures in Sonora Canyon sandstones in Sutton County, Texas. Data obtained from three cored wells through a cooperative research program conducted by the Gas Research Institute and industry show that natural fractures are locally abundant. At least three distinct natural fracture classes coexist that have contrasting distributions, characteristic sizes, and/or mineral fills. The most abundant fracture class consists of clay- or clay- and carbonate-filled fractures existing only in siderite-cemented zones in sandstones. Owing to their clay content, these fractures locally may be barriers to fluid flow and their presence could cause reservoir heterogeneity and anisotropy. Calcite- and quartz-cemented fractures are less common fracture classes. These fractures are larger than those in siderite layers and are partly open as a result of propping by diagenetic minerals. Our results show that fractures in Sonora Canyon sandstones should be considered in completion and stimulation design. For example, high treatment pressures observed in some Canyon Sandstone stimulations may be due to natural fractures promoting propagation of multiple fracture strands near the wellbore. Inconsistencies between hydraulic fracture strike and maximum horizontal stress may be due to natural fractures guiding hydraulic fracture growth.
Fracture Identification and Characterization Using Cores, FMS, CAST, and Borehole Camera: Devonian Shale, Pike County, Kentucky
Authors: Kubik West , Lowry Patrick 
Published: December 2007

ABSTRACT
An accurate characterization of natural fractures is an important part of reservoir exploitation in the gas-bearing Devonian shales of the Appalachian Basin. These reservoirs commonly have very low matrix permeabilities (10-9 to 10-7 md), and a well developed natural fracture system must be present to provide sufficient deliverability for economic production. A detailed fracture description is crucial to proper reservoir modeling and simulation.
Fractures have been identified and described in 440 feet of oriented whole core from two research wells in eastern Pike County, Kentucky. FMS, CAST, and Borehole Camera data have also been acquired, and the core data was used as a basis for the interpretation of these tools. Each tool has its own unique advantages and disadvantages, and guidelines have been established for the optimum use and interpretation of each.
The complex nature of the fracture systems in these reservoirs often pose special problems in fracture identification using these borehole imaging tools. The ability to properly characterize fractures in this reservoir is strongly influenced by the apparently very fine fracture apertures and limited fracture vertical extent.
Whole core represents the best source of data for a detailed, accurate fractured reservoir interpretation. The FMS and CAST are good fracture detection tools, but should be tied to whole core data. The borehole camera, though less quantitative than other tools, represents a reliable source of fracture data, and is inexpensive to acquire and interpret.
Perforation Design Models for Heterogeneous, Multiphase Flow
Authors: Behie Alda , Settari Antonin 
Published: December 2007

ABSTRACT
Design of perforating for optimal productivity is currently based on semi-analytical techniques or charts developed with the use of finite element models. Both methods are severely restricted by their limiting assumptions, while the direct use of finite element models is impractical for field design work. This paper describes the development and application of two new, practical finite difference models for the determination of the productivity of single perforation and multi-perforation systems in single phase as well as multiphase flow. The first models flow through laboratory cores. The second models multiple perforations in a field context. The latter allows any arbitrary perforation geometry, including irregular spacing; gun eccentricity; gravel packed completions; drilling damage; and complex reservoir heterogeneity. In addition, the field model can be applied to vertical or horizontal wells, and can be also used for analyzing RFT pressure tests. The models have been tested and validated against published results including laboratory cores and perforated completions. The validation and application work has yielded a number of interesting findings and some important practical implications for perforating design.
A Study of the Damage Zone Created by Shaped-Charge Perforating
Authors: Yew C. H. , Zhang Xichang 
Published: December 2007

ABSTRACT
A high amplitude pressure pulse was produced by the shaped charge during perforation. The method of characteristics was applied to study the damaged zone created around the perforating tunnel. The analytical results offered an analytical explanation to the experimental observations made by Pucknell and Behrmann1. It was demonstrated that the pore fluid played a major role for the damage surrounding the perforated hole.
Prediction and Analysis of Performance of Gas Wells Producing from Reservoirs Containing Several Noncommunicating Layers
Authors: Dougherty Elmer L. , Juber Fahmi , Chang Jincai 
Published: December 2007

Abstract
This paper studies performance of gas wells producing from a reservoir containing several noncommunicating layers. Predictions were made with a newly developed simulator that performs a complete "nodal analysis" on each time step to determine flow capacity. The four categories of results given are; (1) the excellent correlation of predicted performance of 1- & 2-layer reservoirs with published data validates the novel mathematical approach used in our simulator, (2) for a 5-layer system comparison of simulated results to published values obtained with an analytical solution finds only partial agreement, (3) predicted recoveries after aggregating layers of differing permeability show that layer combinations must be chosen carefully to avoid large errors in predicted recovery and (4) the turbulence coefficient must be defined on a unit thickness basis to obtain correct results for layered systems.
Log-Based Gas Content and Resource Estimates for the Antrim Shale, Michigan Basin
Authors: Decker A. D. , Hill D. G. , Wicks D. E. 
Published: December 2007

ABSTRACT
Antrim Shale multicomponent gas storage mechanisms of adsorption, porosity and solution in bitumen preclude the use of conventional gas-in-place volumetric calculations. Total in-situ gas content has been measured using canister degassing techniques adapted from coalbed methane technologies. Gas measurements ranged from approximately 5 scf/t to 166 scf/t. Gas contents exceed apparent gas-filled porosity by 6 to 8 times where organic content is high. Cross plots of gas content to companion TOC and density measurement resulted in a direct correlation between increasing gas content corresponding to progressive increases in organic matter and an inverse relationship between increasing gas content and decreasing density. The linear function relating density and gas content can be used in conjunction with open-hole log bulk density measurements to calculate gas-in-place.
A side-by-side comparison of gas content measurements from rotary sidewall core and whole core demonstrated that the measurements from both core sampling types are of equal accuracy. From the standpoint of cost, sample homogeniety and sampling selection, rotary sidewall cores are preferred over whole core. The total gas contained in the shale can be completely released as a single measurement by crushing the core upon retrieval. Utilizing the on-site gas content measurements, density/gas content relationship and density log it is possible for the first time to locate and quantify gas bearing Antrim shale intervals from well logs.
A Quick Technique To Define Compressibility Characteristics of Hydrocarbon Reservoir
Authors: Unalmiser Servet , Swalwell T. J. 
Published: December 2007

ABSTRACT
During the production of reservoir fluids, the pore fluid pressure decreases as the overburden pressure remains constant Consequently, pore compression occurs as the disparity between external and internal pressure increases. The technique developed in this study has a different approach to the conventional method resulting in a procedure which is both highly efficient and cost effective. This is achieved by neglecting the cr, which is typically an order of ten less than the cb, thus permitting the almost routine determination of cp. A microcomputer controlled porosimeter has been utilized to carry out compressibility studies to obtain rapid reliable results in a highly cost effective manner. The compressibility characteristics of twelve samples, 2 inches in length and 1.5 inch in diameter, can be determined to a maximum frame stress of 10,000 psi in a matter of hours. The applied technique assumes that: (a) pore compressibility behavior depends only on the effective frame stress based on the theory of poroelasticity; (b) irreducible brine and rock matrix expansion due to reduction in pore pressure are negligible; (c) hydrostatic pore volume compressibility can be converted to uniaxial strain condition based on constant Poisson's ratio for all loading conditions.
Demonstrative studies were applied to core samples from limestone and sandstone reservoirs. A total of 714 carbonate plugs were tested at five different frame stresses between 500 and 3,500 psi. A further 32 sandstone samples were tested, primarily at four different pressures ranging from 500 psi to 3,500 psi. Of these six samples were tested at pressures from 4,000 psi to 9,500 psi at 500 psi increments. An exponential relationship in the form of: Eq. (1)cp=−mP
was found to give excellent correlation with an R2&gt; 97% for all cases. The slope of the exponential line allows one to determine the pore volume compressibility, porosity at stress, and relative porosity change of each core plug at any pressure corresponding to the relevant depth.
Reservoir Quality and Well Response to Stimulation in Frontier Sandstones, Moxa Arch, Southwest Wyoming
Authors: LaFollette R. F. , Davis B. J. 
Published: December 2007

ABSTRACT
Reservoir quality and response to stimulation vary significantly in the Frontier Formation. Available geological and engineering data have been integrated with a core study to better understand Frontier reservoir properties and stimulation response.
Second Frontier reservoir quality is best developed in marine upper shoreface/bar and fluvial channel depositional systems. Lower shoreface sandstones are generally non-reservoir-quality material. Flow study results support the use of crosslinked gelled-water frac fluids from pH 4.0 to pH 10.5. The major potential completion problem identified in the Frontier is fines migration of mixed-layer illite/smectite clay. Analysis of production and stimulation data from the Church Buttes/Bruff area indicates that foam fracs may yield higher initial flow rates, but crosslinked gelled-water treatments result in higher ultimate recoveries.