bluuebunny/crossref_metadata_2025_split huggingface dataset:
Identification of Successful Practices in Hydraulic Fracturing Using Intelligent Data Mining Tools; Application to the Codell Formation in the DJ-Basin
Authors: Mohaghegh S. D. , Popa A. , Gaskari R. , Ameri S. , Wolhart S. L. 
Published: December 2007

Abstract
In a detail data mining study about 150 wells that have been completed in the Codell formation, DJ Basin, have been analyzed to identify successful practices in hydraulic fracturing. The Codell formation is a low permeability sandstone within the Wattenburg field in the DJ Basin of Colorado. Since 1997 over 1500 Codell wells have been restimulated. As part of a Gas Research Institute restimulation project 150 wells were studied to optimize candidate selection and identify successful practices.
Hydraulic fracturing is an economic way of increasing gas well productivity. Hydraulic fracturing is routinely performed on many gas wells in fields that contain hundreds of wells. During the process of hydraulically fracturing gas wells over many years, companies usually record the relevant data on methods and materials in a database. These databases usually include general information such as date of the job, Service Company performing the job, fluid type and amount, proppant type and amount, and pump rate. Sometimes more detail information may be available such as breakers, additives, amount of nitrogen, and ISIP to name a few.
These data are usually of little use in complex 3-D hydraulic fracture simulators. These models require additional and more detailed information. On the other hand, the collected data contain valuable information that can be processed using virtual intelligence tools. The process covered in this paper takes the above-mentioned data and couples it with general information from each well (things like latitude, longitude and elevation), any information available from log analysis and production data. The conclusion of the analysis is a set of successful practices that has been implemented in a particular field and recommendations on how to precede with further hydraulic fracture jobs.
In this paper the results of applying this process to about 150 Codell wells during the GRI sponsored project is presented. This process provides an important step toward constructing a comprehensive set of methods and processes for data mining, knowledge discovery, and data-knowledge fusion from data sets in oil and gas industry.
Development of an Intelligent Distributed Management System for Automated Wells (SGPA)
Authors: Cerqueira Jes F. , Corrêa Jose F. , Lepkison Herman , Bittencourt A. C. , Schnitman L. , Jesus A. B. 
Published: December 2007

Abstract
The differences between foreseen results in lift well project related to the obtained in production phase increases preventing and correcting actions necessary to optimize well production. The larger number of wells and its analysis complexity don't allow to conduct the cluster of actions entirely.
To help in this task, the automation of petroleum wells has grown expressively. Over 700 wells in Brazil, at Bahia State, are provided with PLCs using A.I. techniques for their control. This sort of automation generates an expressive amount of data that can be used to optimize the lift systems production. Besides this, it also allows local control and remote observation of many wells in real time basis.
This paper presents an approach for an automated lift well management system, called SGPA. SGPA supports diagnosing and proposes solutions to optimize automated wells production. SGPA focus mainly on Rod-Pump wells management. However, other lift systems can be included as well.
SGPA operates under three main subsystems: (1) Data consistency module, makes the acquisition and consistency of information from different sources. This information is treated and shown in a friendly interface, and it is used in other subsystems. (2) Dynamometric Cards apprenticeships module, allows the user to generate and train the system understanding of the dynamometric cards pattern behavior. These patterns can be used by the PLC's which control the well, and by the SGPA pattern recognition module to support the well diagnose and improve the well lift. (3) Knowledge module that makes well analysis. The knowledge subsystem determine symptoms, makes diagnostics and adds intelligence for the well optimizing and correcting actions. The knowledge representation uses Symbolic Neural Networks (SNN) and Fuzzy Logic (FL) for its constructions and apprenticeship and evolution.
It is understood that lift systems automation comes to be a complex system that distinguishes from other traditional approaches by successfully dealing with huge amount of information to cope its mission, despite the high level of empiricism and apparently erratic behavior due to well peculiarities, demanding rigorous status observation. Such reality and the present technology state-of-art justify SGPA development.
Proper Core-Based Petrophysical Analysis Doubles Size of Ha'py Field
Authors: Bryant William T. , Truman Robert B. 
Published: December 2007

Abstract
The Ha'py Field is located offshore Egypt and is part of the Pliocene producing trend north of the Nile Delta. The original interpretation for the gas in place for the Ha'py Field by Amoco and others was 989 Bcf. Re-evaluation of the field increased the gas in place to 2045 Bcf proven. Subsequent production in the field has substantiated the large increase of the gas in place as a result of the re-evaluation. The initial underestimation of the gas in place was a result of the use of an incorrect log-derived porosity model. This porosity model is not compatible with the petrophysical water saturation relationship used. The incompatibility stems from the fact that petroleum engineers and petrophysicists have different definitions for the terms effective porosity and total porosity. The difference in definitions may lead a petrophysicist to improperly model the well logs to the available core analysis. In addition, the engineer may mis-apply the petrophysicist's results to the reservoir characterization. This improper application leads to a substantial underestimation of hydrocarbon pore volume. The higher the clay and shale content in the reservoir, the greater the error. Definitions will be clarified and explained as they apply to core analysis, reservoir engineering and petrophysics, along with examples using core analysis. Correct modeling of porosity data in these shaly reservoirs lead to the increased estimation of the gas in place.
Maximizing Yibal's Remaining Value
Authors: Team Yibal V2V 
Published: December 2007

Abstract
The Yibal field is one of the cornerstones of Oman's oil production, currently supplying ca. 12 % of the country's daily production. The Yibal field has been on production since 1969 and reached peak production in 1997. Since then the field has been experiencing a rapid decline. This paper discusses the currently ongoing activities to arrest this decline and to ensure that the value of the remaining producible volumes in the Yibal field is maximized using Shell's ‘Volume-to Value’ process.
Prudhoe Bay E-Field Production Optimization System Based on Integrated Reservoir and Facility Simulation
Authors: Litvak Michael L. , Hutchins Lynda A. , Skinner Roger C. , Darlow Bruce L. , Wood Robert C. , Kuest L. John 
Published: December 2007

Abstract
This paper describes the E-field production optimization system (EFOS), recently developed for the Prudhoe Bay oil field in Alaska. EFOS is based on an integrated compositional model of the reservoir and surface facilities. A commercial reservoir and surface facility simulator is used for integrated fluid flow modeling in the reservoir, well tubing strings, surface pipeline network system and surface separation facilities.
EFOS is designed as an operational tool for short-term field production optimization and debottlenecking studies as opposed to a tool for long-term reservoir modeling studies. While full reservoir modeling capability is an option, and is a valid approach to daily optimization for small fields, it is not a practical approach at Prudhoe Bay where there are over 800 producing wells. To facilitate a practical alternative, an option was developed to use well inflow performance curves to predict well performance as opposed to running the full reservoir model.
EFOS consists of the following major components: automatic data preparation, automatic model tuning to match available field production data, production optimization, and a user-friendly interface. Procedures were developed for automatic data collection and creation of simulator input data sets from data gathered by existing process control systems.
In the tuning phase, simulation parameters are automatically adjusted within physically justifiable ranges to match field measurements of well production rates, well tubinghead pressures, and flowline pressures at the specified simulation time.
To optimize production, robust mixed integer optimization algorithms are applied. Well production rates, well allocations to separator trains and, optionally, gas lift rates are selected that maximize field oil production subject to reservoir and facility constraints. The selected objective function is maximized in each simulation time step.
The foreground user-friendly interface is an integral part of one of the Prudhoe Bay process control system databases, with the reservoir simulator running in the background. The interface between the two systems is enabled through a new interactive mode of reservoir simulator operation.
Some examples of the EFOS application are described which also outline the system efficiency. EFOS is based on commercial software permitting its application in a large variety of oil and gas fields.
Coiled-Tubing Fracturing Increases Deliverability, Recoverable Reserves, and NPV of Infill Development Wells in a Mature Shallow Gas Field
Authors: Wolny Stanley F. , Schiffner Glen , Schmelzl Eric G. , Jamieson Merrill , Stromquist Marty 
Published: December 2007

Abstract
A comparative study was undertaken to review the production results, reserve recovery, and economics between conventional hydraulic stage fracturing and coiled-tubing (CT) fracturing on infill development wells in a mature shallow gas field near Medicine Hat in southeastern Alberta, Canada. Selective stimulation through coiled tubing was developed for this area as a response to demands operators placed on service companies to improve the completion efficiency of a shallow gas well with multizone potential. The main benefit of CT fracturing is that each prospective productive interval is selectively stimulated. This translates to improved deliverability, reserve recovery, and project economics. The process also improves logistics, decreases workforce requirements, and minimizes environmental impact. This paper provides in detail how these benefits can be accomplished with coiled-tubing fracturing.
Toto, We're Not in West Texas Anymore; A Challenging Examination of the Historical Global Crude Oil Production Capacity, Demand, Price and the Changing Elasticies
Authors: Jentsch W. A. , Merryman A. A. , Littell G. S. , Groppe H. 
Published: December 2007

Abstract
The basic fundamentals and drivers of changing supply and demand and their affect upon price have changed dramatically through time. Do you recall in the early 80's when the popular belief was that crude would go to $100/bbl or in 1998 when many believed that crude would return to below $10/bbl for the foreseeable future.
The results of this paper will better equip the reader to understand why neither of these beliefs were correct and never will be. This paper will also provide a clearer understanding of the macro supply, demand and pricing environment to assist both the engineers and managers with their critical long-term decision-making.
The drivers in both the short-term and the long-term perspectives of the global crude oil production capacity, demand and price differ. The short-term perspective, which tends to have a greater influence on our strategies and decisions, is typically driven by inventories and influenced by politics, perceptions, seasonal factors and supply disruptions, among others.
The main focus of this paper is on the longer-term perspective or the macro level of global crude oil production capacity, demand and pricing from 1945 to present. In particular, the changes in the elasticity of global demand, supply and price are analyzed and highlighted. Briefly, the regional supply and demand will also be examined.
Trend analysis will include both artificial as well as natural effects such as maturing fields, regulatory effects, and the changing differential (excess capacity) between demand and supply. We will discuss the potential supply and price trends assuming demand continues to increase at the current rate.
An Effective Technique of Estimating Drainage Shape, Magnitude and Orientation in a Low-Permeability Gas Sand
Authors: Robinson Ryan L. , Engler Thomas W. 
Published: December 2007

Abstract
This study presents a methodology to determine the optimal infill location for the Mesaverde Field in the San Juan Basin, New Mexico. Evaluation techniques include: (1) Log-derived cumulative distributions to develop producing interval limits, (2) Seismic analysis to identify fractures, (3) Type-curve analysis to generate reservoir properties, (4) Production decline analysis for establishing inter-well relationships, (5) Geostatistical modeling to distribute reservoir characteristics, and (6) Flow simulation for verification and formation contribution. The result of incorporating these evaluation methods is a map that provides limits to the drainage area.
Specific information obtained is degree of anisotropy, aspect ratio, and the magnitude and orientation of the permeability. In the study area, the dominant fracture orientation was N30°E as indicated by seismic curvature analysis and confirmed with production decline analysis. Type-curve analysis resulted in an average well permeability from 0.10 md to 7.75 md. It was demonstrated that a minimum permeability ratio (kmax/kmm) 13.7:1 was sufficient to match the interfering production response exhibited between wells. Limited infill drilling was identified on the drainage maps, as the existing wells exhibit an average drainage area of approximately 160 acres. Potential recovery was estimated to be 800 MMscf per well for the selected locations with the best chance for success.
A common problem in infill drilling projects is to decide to target prolific areas or low reservoir quality areas in the Mesaverde Group. This study area consists of high equivalent permeability as a function of naturally occurring fracture networks, when compared to the rest of the basin. The likelihood of widespread drainage to occur is high. Therefore, the potential for infill drilling may be limited. This work demonstrated that although limited potential, exists, proper evaluation methods established in this work might be useful to identify the best location.
The Effect of Cement Heat of Hydration on the Maximum Annular Temperature of Oil and Gas Wells
Authors: Dillenbeck R. L. , Heinold T. , Rogers M. J. , Mombourquette I. G. 
Published: December 2007

Abstract
Recent advances in electronics technology have made it possible to monitor and record real-time annular temperatures in operational wells, both during and after primary cementing. The advances have allowed operators to record the entire annular temperature history of their wells, including the critical period when cement hydration occurs. The ability to record these actual temperatures can significantly impact the oilfield cementing industry in several ways. Most significantly, current accepted practice within the industry is to test certain critical aspects of set cement, such as compressive and tensile strength, at bottomhole static temperature (BHST). If the short-term maximum annular temperature is significantly different from the later BHST of the well, then laboratory tests run on cement at a steady BHST may prove to be inaccurate based on the actual temperature encountered by a cement slurry down hole. Also of concern is the fact that since the maximum temperature spike from hydrating cement may not occur until after the cement has achieved an initial set, the magnitude of any subsequent temperature change after the initial set may have profound effects on induced stress in the cement sheath, as well as the casing and formation.
Based on actual field measurements of annular temperatures, the authors will detail how the variable factors of individual heat of hydration, relative annular geometry, and final BHST interact to produce short-term maximum temperatures in the cement sheath. In some instances, these maximum temperatures can vary significantly from the stabilized BHST in a well. The actual annular temperature data was recovered from wells in both North and South America and includes both shallow as well as deep well applications.
The Kitchen Prospects, Cook Inlet Alaska: A Giant Natural Gas Accumulation
Authors: Demarchos A. S. , Warthen R. C. , Davis D. S. , Economides M. J. 
Published: December 2007

Abstract
Natural gas reserves potentially rivaling those of the North Slope have been recently identified in two, never before tested structures, in the Cook Inlet Basin, Alaska. The discovery is a culmination of years of local geological experience, and seismic analysis of existing data using the Energy Absorption Analysis technique (Mitchell, 1997). It is undoubtedly the largest hydrocarbon reservoir discovery in the Cook Inlet, Alaska. They have been named as the Kitchen Prospects. One structure, which has never been tested before, is estimated to hold recoverable reserves of at least 12.7 Trillion cubic feet of gas (Tcf), which is 1 and ½ times the ultimate recovery of the Cook Inlet Basin prior to this discovery (Sherwood, 2001). The total identified recoverable natural gas reserves are estimated to be over 27 Tcf, three times the ultimate gas reserves of the Cook Inlet Basin. Full field development, based on past experiences could exceed 3 billion cubic feet of gas per day (Bcf/d). Current natural gas production in the Cook Inlet is 215 Bcf/year, net (DOE/EIA, 2001).
The limited natural gas market in the Cook Inlet area (local consumption, a fertilizer plant and a small LNG plant) would pose a severe problem in developing new large natural gas reserves. However, the recent national move towards natural gas as the premier fuel of the future the recent energy crisis in California and the West Coast become compelling reasons for the expansion of the existing LNG terminal, or for a new floating LNG, which could supply California with at least 500 MMCF/d. Other options include the substantial expansion of the Ammonia/Urea plant (another 145 MMCF/d) and supplying the city of Anchorage, and Southern Eastern Alaska in general, a political obstacle to the proposed, and more logical, natural gas pipeline from the North Slope under the Beaufort Sea and down the McKenzie Delta to the Canadian pipeline system and into the United States.
Integrating Wellbore Flow Images with a Conventional Production Log Interpretation Method
Authors: Frisch Gary , Perkins Tegwyn , Quirein John 
Published: December 2007

Abstract
Horizontal well production logging (PL) measurements, especially center-sample devices, have been misleading in evaluation of the flowing stream. These inaccuracies are due to the natural segregation of the fluids owing to the difference in the phase densities.
A new multiphase holdup tool and interpretation method has been developed that provides accurate determination of holdups and flowrates in horizontal wells. The multiphase holdup tool uses 12 capacitance-sensing circuits with multiple arm arrangements to provide an excellent image of the holdup pattern. Since these sensors are on the same cross-sectional plane, depth inconsistencies are not a factor in the interpretation. Each sensor responds to the permittivity (dielectric constant) of the surrounding fluids, and the response can be converted to a phase holdup by applying the known sensor calibration. Consideration of each sensor's position relative to the wellbore allows for prediction of the total phase holdup across the entire wellbore cross sectional plane.
Advanced analysis packages allow the user to interact with the computed holdups, providing an easy method of interpretation. Different views of the wellbore, cross-sectional displays, and displays incorporating the wellbore trajectory allow accurate and detailed analysis that is critical for understanding flow in horizontal wells. Once the holdup of each phase (gas, oil, and water) is determined, an additional interpretation package allows a complete production log analysis including flowrates in a very difficult environment. The results of these analysis packages allow an operator to understand, modify, and improve the productivity of a horizontal well.
Application of Shear Anisotropy from a New Generation Crossed Dipole Acoustic Tool
Authors: Fogal Jim , Kessler Calvin , Varsamis Georgios 
Published: December 2007

Abstract
A new generation crossed-dipole acoustic-logging tool acquires data that can be utilized to calculate shear anisotropy. This new tool, the WaveSonic™ tool, was designed using a systems approach so that tool functions such as transmitted pulse shape, center frequency, amplitude and duration are programmable from the surface. Additionally, the tool design is robust enough to allow drillpipe conveyance if well conditions warrant. It can also be combined with other logging tools and is "double-ended", allowing it to be located at any position in the logging tool-string.
Shear data can be collected in orthogonal X-Y directions and oriented by a navigational package using data from a four or six-arm caliper device run with the WaveSonic tool. From these measurements, shear slowness anisotropy can be determined, as well as the direction of the fast shear slowness. These slowness values provide input to a model that calculates maximum and minimum principal stresses and their orientations. Information about principal stresses can be instrumental in optimizing completion and stimulation design. In cases where natural fracture information is desired, crossed dipole data can be used to help detect and orient such fracture systems.